2013-09JPT Magazine

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SEPTEMBER 2013JOURNAL OF PETROLEUM TECHNOLOGY • www.spe.org/jpt

RESERVOIR PERFORMANCEAND MONITORING

COMPLETIONS TODAY

DRILLINGMANAGEMENTAND AUTOMATION

2014 SPE President Jeff Spath

Drilling in Space

Dry Tree Semisubmersibles

An Incubator for Startups

University R&D

FEATURES

Sept13_JPT_Cover.indd 1 8/16/13 12:16 PM

6 Performance Indices

10 Regional Update

12 Company News

14 Comments

18 Technology Applications

24 Technology Update

50 Young Technology Showcase

167 People

169 SPE News

171 Professional Services

175 Advertisers’ Index

176 SPE Events

Cover: National Oilwell Varco’s hardware-in-the-loop drilling simulator supports drilling automation. Photo courtesy of National Oilwell Varco.

16 GUEST EDITORIAL: CREATING A COMMON SAFETY CULTURE The oil and gas industry can enhance safety practices by developing shared guidelines for work control, isolation standards, risk assessment, and safety observation programs.

32 2014 SPE PRESIDENT JEFF SPATH The incoming SPE president shares his goals and strategy with SPE and its members for the coming year.

42 SPE STRATEGIC PLAN IDENTIFIES FOUR PRIORITIES The new 5-year Strategic Framework will prioritize capability development, knowledge transfer, professionalism and social responsibility, and public education about the profession and industry issues.

56 DRILLING IN EXTREME ENVIRONMENTS: SPACE DRILLING AND THE OIL AND GAS INDUSTRY Drilling in extreme environments is helping drive advances in the oil and gas industry and presents analogs that can be mined for insight.

70 DRY TREE SEMISUBMERSIBLES: THE NEXT DEEPWATER OPTION Offshore engineering companies are taking existing technologies and lessons learned from floating rigs to create a new platform design that will allow drilling in deeper waters.

78 E&P SOFTWARE: THE NEXT GENERATION New ventures supported by Surge Accelerator, a company that offers financial support, training, and advice from mentors, are creating software to improve oil and gas operations.

86 SAUDI ARAMCO PRODUCTION HITS HISTORIC HIGHS The discovery of additional unconventional resources, new oil recovery techniques, and more university collaborations have led to Saudi Aramco’s record performance and increased technical capabilities.

88 INDUSTRY/RESEARCH COLLABORATION ADVANCES OIL AND GAS TECHNOLOGIES Universities are working on some of the oil and gas industry’s most challenging hurdles to develop new technologies and techniques to meet the increasing global demand for energy.

102 MANAGEMENT: TOP TRENDS IN THE OIL AND GAS SECTOR Deloitte’s fourth annual Oil & Gas Reality Check presents five trends affecting the oil and gas industry globally and discusses the direction these trends may follow.

166 LEGION OF HONOR SPE welcomes 83 members with 50 years of consecutive membership into the Legion of Honor.

An Official Publication of the Society of Petroleum Engineers.Printed in US. Copyright 2013, Society of Petroleum Engineers.

Volume 65 • Number 9

ContentsSept13.indd 1 8/13/13 7:06 AM

TECHNOLOGY

The complete SPE technical papers featured in this issue are available free to SPE members for two months at www.spe.org/jpt.

108 Reservoir Performance and MonitoringErik Vikane, SPE, Production Manager, Statoil Oseberg East

109 New Time/Rate Relations for Decline-Curve Analysis of Unconventional Reservoirs

114 Instilling Realism in Production Forecasting Decreases Chances of Underperformance

118 Conformance Control and Proactive Reservoir Management Improve Deepwater Production

123 Distributed Microchip System Records Subsurface Temperature and Pressure

126 Completions TodayPaul Cameron, SPE, Senior Well-Engineering Adviser, Global Wells Organization, BP

127 Advancements in Completion Technology Increase Production in the Williston Basin

130 North American Completion Technologies Unlock the Amin Tight Gas Formation

136 Intelligent-Well Completion in the Troll Field Enables Feed-Through Zonal Isolation

140 Evaluation of Established Cleanup Models in Dynamic Underbalanced Perforating

146 Drilling Management and AutomationJ.C. Cunha, SPE, Drilling Manager, Ecopetrol America

147 Design of an Automated Drilling-Prediction System

152 Management Strategies Optimize Drilling and Completion Operations

156 Integrated-Technology Approach Enables Successful Prospect Evaluations in Malaysia

160 Real-Time Analysis for Remote Operations Centers

ContentsSept13.indd 3 8/13/13 12:55 PM

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JPT Online Is ChangingThe new JPT Web page is a one-stop place for SPE members to access print and digital editions. The JPT website is optimized for phones and tablets. The site contains:

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Access the new site at www.spe.org/jpt.

ContentsSept13.indd 5 8/12/13 12:47 PM

PERFORMANCE INDICES

66 JPT • SEPTEMBER 2013

PERFORMANCE INDICES

wORlD CRuDE OIl PRODuCtION+‡

tHOuSAND BOPD

OPEC 2012 NOV DEC 2013 JAN FEB MAR APR

Algeria 1483 1485 1490 1490 1490 1510

Angola 1770 1790 1840 1790 1840 1855

Ecuador 504 503 505 506 504 516

Iran 3000 3100 3200 3200 3200 3200

Iraq 3225 3125 3075 3075 3075 3175

Kuwait* 2650 2650 2650 2650 2650 2650

libya 1450 1350 1350 1400 1350 1450

Nigeria 2280 2520 2460 2420 2445 2400

Qatar 1200 1200 1200 1200 1200 1200

Saudi Arabia* 9540 9240 9140 9140 9140 9440

uAE 2820 2820 2820 2820 2820 2820

Venezuela 2300 2300 2300 2300 2300 2300

TOTAL 32222 32083 32030 31991 32014 32516

tHOuSAND BOPD

NON-OPEC 2012 NOV DEC 2013 JAN FEB MAR APR

Argentina 533 546 534 534 536 592

Australia 379 371 282 309 328 341

Azerbaijan 866 916 910 903 892 886

Brazil 2045 2105 2054 2017 1853 1923

Canada 3281 3427 3327 3537 3637 3637

China 4232 4224 4168 4146 4164 4174

Colombia 970 984 1010 998 1013 1007

Denmark 202 200 187 197 193 183

Egypt 551 551 548 547 545 543

Eq. Guinea 297 297 282 282 282 282

Gabon 240 240 240 239 239 238

India 774 773 763 767 777 773

Indonesia 848 850 834 834 840 827

Kazakhstan 1564 1545 1564 1583 1588 1572

Malaysia 550 557 546 552 536 544

Mexico 2622 2606 2609 2602 2562 2564

Norway 1517 1558 1545 1502 1498 1567

Oman 947 950 939 944 934 910

Russia 10048 10018 9995 9990 9995 10002

Sudan 90 101 106 106 112 115

Syria 131 136 131 133 91 71

uK 864 923 913 826 1041 805

uSA 7052 7095 7047 7145 7177 7353

Vietnam 362 357 345 355 337 359

Yemen 162 169 162 162 140 119

Other 2444 2455 2434 2453 2451 2445

Total 43570 43953 43475 43663 43761 43833

Total World 75792 76036 75506 75654 75775 76349

Perf_Indices_Sept.indd 6 8/19/13 10:41 AM

PERFORMANCE INDICES


PERFORMANCE INDICES

HENRY HuB GulF COASt NAtuRAl GAS SPOt PRICE*‡

wORlD ROtARY RIG COuNt†

REGION2013 JAN FEB MAR APR MAY JUN JUL

uS 1757 1762 1756 1755 1767 1761 1766

Canada 503 642 464 153 128 183 291

latin America 414 427 437 429 424 423 418

Europe 134 135 133 136 124 138 139

Middle East 379 350 336 354 362 389 379

Africa 115 113 115 125 124 133 128

Asia Pacific 237 250 247 257 249 250 241

TOTAL 3539 3679 3488 3209 3178 3277 3362

wORlD CRuDE OIl PRICES (uSD/bbl)‡

102.62 87.90 113.36 94.13 112.86 94.51 111.71 89.49

2012 JUL AUG SEP OCT

109.06 86.53 109.49 87.86 112.96 94.76 116.02 95.31

NOV DEC 2013 JAN FEB

108.47 92.94 102.25 92.02 102.56 94.51 102.92 95.77

MAR APR MAY JUN

Brent WTI

wORlD OIl SuPPlY AND DEMAND1‡

MIllION BOPD 2012 2013

Quarter 3rd 4th 1st 2nd

SUPPLY 89.03 89.33 88.60 89.79

DEMAND 89.27 89.82 89.15 89.54

INDICES KEY + Figures do not include NGLs and oil from nonconventional sources.

* Includes approximately one-half of Neutral Zone production.

1 Includes crude oil, lease condensates, natural gas plant liquids, other hydrocarbons for refinery feedstocks, refinery gains, alcohol, and liquids produced from nonconventional sources.

† Source: Baker Hughes. * The US Dept. of Energy/Energy Information Administration discontinued its reporting of US Natural Gas Wellhead

Prices, replacing them with Henry Hub Gulf Coast Natural Gas Spot Prices.

‡ Source: US Dept. of Energy/Energy Information Admin.

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Perf_Indices_Sept.indd 8 8/19/13 10:41 AM

REGIONAL UPDATE


AFRICA

◗◗ A discovery was made at the Ogo-1 well offshore Nigeria. The well reached a total depth of 3206 m and encountered a gross hydrocarbon section of 524 ft with 216 ft of net stacked pay. Optimum Petroleum Development (60%) is the operator in partnership with Afren (22.86%) and Lekoil (17.14%).

ASIA

◗◗ Drilling has begun on the Lukut Updip-1 exploratory well on Brunei Block L in Brunei. It has a planned true vertical depth of 2431 m targeting deltaic and base slope sand deposits of Middle Miocene age. AED Southeast Asia (50%) is the operator in partnership with Kulczyk Oil Brunei (40%) and a private Brunei company (10%).

◗◗ Salamander Energy has begun its multi-well exploration program in Block G4/50 off the Gulf of Thailand. The group plans to drill six exploration wells this year followed by further exploration drilling next year. The block covers 2,239 sq miles and contains five sub-basins. Salamander holds a 100% operating interest.

◗◗ Gas condensate was discovered from a deep reservoir at the Adam X-1 exploration well in Block 2568-13 in the Hala field in Pakistan. During testing, the well flowed at 14.3 MMcf/D of gas and 125 BOPD (condensate) at a 40/64-in. choke. Pakistan Petroleum (65%) is the operator in partnership with Mari Petroleum (35%).

◗◗ Production has begun on the offshore Wenchang 8-3E oil field in China. The field is located in the western Pearl River Mouth basin in China and has an average water depth of approximately 110 m to 120 m. China National Offshore Oil Corporation is the operator with a 100% interest.

◗◗ The Tayum-1 exploration well encountered approximately 49 vertical ft of net gas pay from multiple sandstone intervals within the Miocene and Pliocene section. The well is located in the Kutai production sharing contract offshore Kalimantan in Indonesia. KrisEnergy (54.6%) is the operator in partnership with

Salamander Energy (23.4%) and Orchid Kutai (22%).

◗◗ Oil was discovered at the Parit Minyak-2 exploration well located onshore north Sumatra in Indonesia. The well was drilled to a total depth of 2812 m, during which several oil shows were noted within the Eocene/Oligocene Pematang group. From the interval of 2480 m to 2539 m, the well flowed 37 °API oil at a rate of 200 to 400 B/D with no water. Pacific Oil & Gas (Kisaran) (55%) is the operator in partnership with Pacific Oil & Gas (Sumatera) (22.5%) and New Zealand Oil & Gas (22.5%).

AUSTRALIA

◗◗ Drilling began on Hooper-1, an exploration well in PEL 92, in the Cooper basin in South Australia. The well will be drilled on a 3D seismic defined anticline in the northwest section of PEL 92 and has a planned total depth of 1820 m, targeting Namur Sandstone. Beach Energy (75%) is the operator in partnership with Cooper Energy (25%).

EUROPE

◗◗ The Norvarg appraisal well confirmed the presence of hydrocarbons in the Kobbe formation in production license 535 in the Norwegian sector of the Barents Sea. Drillstem tests to assess the quality of the reservoir and the volume potential in the northeastern part of the Norvarg closure will be performed. Total (40%) is the operator in partnership with Det norske (20%), North Energy (20%), Valiant Petroleum (13%), and Rocksource (7%).

◗◗ Seismic data acquisition has begun in the Fedynsky and Central Barents license areas in the ice-free part of the Russian sector of the Barents Sea. The 2D survey is planned to take place over 6,100 miles. Rosneft holds 66.67% of the joint venture, while Eni holds the remainder (33.33%).

◗◗ Drilling began on the 16/2-18S exploratory well in production license 265 in the North Sea. Located in the Cliffhanger North prospect, the well has a planned total depth of 1970 m and will test the presence of the Jurassic reservoir and the quality of fractured and weathered

basement. Statoil Petroleum (40%) is the operator in partnership with Petoro (30%), Det norske oljeselskap (20%), and Lundin Norway (10%).

MIDDLE EAST

◗◗ Gulf Keystone has commenced its development drilling program with the spudding of the Shaikan-10 development well in Iraq. The well is a modular design with a production capacity of 20,000 BOPD. It will be followed by a minimum three-rig development and production drilling program, which will begin early next year.

NORTH AMERICA

◗◗ Drilling has begun on the East Lusk 15 Federal #3 horizontal well in Lea County in New Mexico. The planned depth is 2896 m vertically and 1219 m to 1524 m laterally. FieldPoint Petroleum (43.75%) is the operator in partnership with Cimarex (37.5%) and other unnamed partners (18.75%).

◗◗ The Vicksburg deepwater well in the Gulf of Mexico encountered more than 500 ft of net oil pay after being drilled to a depth of 8042 m. Located in the De Soto Canyon Block 393, the Vicksburg A discovery is estimated to contain recoverable resources of more than 100 million BOE. Royal Dutch Shell (75%) is the operator in partnership with Nexen (25%).

◗◗ Drilling has begun on the Stalder Pad site located in eastern Monroe County in Ohio. The pad has been designed and permitted to drill up to 18 wells (10 Marcellus and 8 Utica). Triad Hunter (50%) is the operator in partnership with Magnum Hunter Resources (50%).

SOUTH AMERICA

◗◗ Oil and gas reserves were discovered at the Chercán 1 well located on the Flamenco block in Chile. The well was drilled to a total depth of 2066 m and flowed at a rate of approximately 4 MMcf/D of gas and 35 BOPD through a choke of 8 mm. GeoPark Holdings (50%) is the operator in partnership with Empresa Nacional de Petroleo de Chile. JPT

RegionalUpdateSept.indd 10 8/13/13 12:59 PM

COMPANY NEWS


MERGERS AND ACQUISITIONS

◗◗ Chesapeake Energy will sell its assets in the northern Eagle Ford Shale and Haynesville Shale to EXCO Operating, a subsidiary of EXCO Resources, for USD 1 billion. The acquisition covers approximately 55,000 net acres from Zavala, Dimmit, La Salle, and Frio counties in Texas, which includes 120 producing wells.

◗◗ GE Oil & Gas bought Lufkin Industries for approximately USD 3.3 billion. Lufkin has more than 110 service centers and nine manufacturing facilities for artificial lift equipment globally.

◗◗ Chesapeake Energy sold a 50% undivided interest in approximately 850,000 acres in northern Oklahoma for USD 1.02 billion to Sinopec International Petroleum Exploration and Production. Assets associated with the transaction produced approximately 9,600 B/D of liquids and 54 MMcf/D of natural gas during the first quarter of the year.

◗◗ Schlumberger bought Gushor, a Canadian-based petroleum geochemistry and fluid analysis company that provides production and exploration solutions for heavy oil and oil sands.

◗◗ Xodus Group bought Dubai-based Prime Energy as part of its major expansion drive in the Middle East. Prime Energy’s team will form part of Xodus’ subsidiary based in Dubai, which will be renamed Xodus-Prime DMCC.

◗◗ Petronas Carigali incorporated a new wholly owned subsidiary, Vestigo Petroleum, to focus on development and production activities from small, marginal, and mature fields in Malaysia and abroad.

◗◗ Vietnam and China have extended an agreement to jointly explore for oil and gas in the Gulf of Tonkin until 2016. The new agreement expands the area covered from 1541 km2 to 4076 km2 under the initial arrangement. The operational responsibilities and costs will be split evenly. The joint exploration is led by Petrovietnam and China National Offshore Oil Corporation.

◗◗ Cameron and Schlumberger received all required regulatory approvals for their joint venture, OneSubsea, which will manufacture and develop products, systems, and services for the subsea oil and gas market. Cameron will hold a 60% interest and Schlumberger the remaining 40%.

◗◗ Cimarex Energy and Chevron will jointly develop Cimarex’s combined Permian Basin acreage in Texas spanning 104,000 acres. Chevron will pay USD 60 million to secure a 50% stake in the Cimarex-built Triple Crown gas gathering and processing system and wells drilled on the acreage.

◗◗ Costain acquired EPC Offshore, resulting in the launch of Costain Upstream, a new divisional operation. The new company will have more than 350 employees and will provide services across the life cycle of upstream offshore oil and gas assets.

◗◗ ALS Global acquired Reservoir Group for USD 533 million. The transaction includes operational infrastructure in approximately 40 sites globally and 900 employees.

COMPANY MOVES

◗◗ Schlumberger announced the official opening of its Schlumberger Reservoir Laboratory in Chengdu, China. The 32,000 ft2 facility offers an integrated suite of petrophysical and geomechanical services to help customers improve hydrocarbon recovery and maximize production throughout the life of their reservoirs.

◗◗ Petronas announced it has begun construction on its first floating liquefied natural gas (LNG) facility in Malaysia in June. The facility will be located in the Kanowit gas field in Block SK306, which is 112 miles offshore Sarawak and will have the capacity to produce 1.2 MTPA of LNG.

CONTRACTS

◗◗ ExxonMobil awarded two contracts for work in its Julia field development in the US Gulf of Mexico (GOM) Walker Ridge block. Oceaneering International will supply 14 miles of electro-hydraulic, steel

tube umbilicals for hydraulic control fluids, chemicals, and electrical power signals in early 2015 to operate and monitor the subsea wells and manifold. A subsidiary of McDermott International will carry out an engineering, procurement, and construction contract including six subsea wells, one six-slot manifold, two umbilicals, six jumpers, two flowlines with two steel catenary risers, two subsea pump modules, and topsides support equipment beginning in the second quarter of 2015.

◗◗ Nido Petroleum Philippines, a wholly owned subsidiary of Nido Petroleum, was awarded a 12-month extension of Sub-Phase 6 of Service Contract 54A by the Philippine Department of Energy. The contract will allow the SC 54A joint venture time to complete engineering and field development studies offshore west Philippines before making a decision to enter Sub-Phase 7.

◗◗ 2H Offshore, an Acteon company, was awarded a contract by Total for the delivery management of the tension leg platform top tensioned riser (TTR) systems for its Moho Nord field development offshore Congo. The company will be responsible for the riser delivery management, including design finalization, procurement management, and inspection services for 17 production and water injection TTRs and one high-pressure drilling riser.

◗◗ Aker Solutions won a contract from Daewoo Shipbuilding and Marine Engineering (DSME) to supply a drilling equipment package a production platform at the Mariner field in the North Sea. The contract includes a complete topside equipment package and support services to DSME’s shipyard in South Korea. Delivery of the contract is expected to be completed in 2015.

◗◗ Wison Offshore & Marine, a subsidiary of the Wison Group, was awarded a contract from China Oilfield Services to supply one 3,000 hp modular drilling rig for use on the Tsimin field in the GOM. Wison will perform the project management, procurement, production engineering, fabrication, load out, offshore installation, and commissioning of the modular drilling rig. JPT

CompanyNewsSept.indd 12 8/12/13 3:29 PM

COMMENTS


Looking Ahead John Donnelly, JPT Editor

Initial forecasts for 2014 predict continued growth in global oil supply, relatively moderate demand, and a potential soften-ing of oil prices. International events could change that picture overnight but, for now, the industry’s three leading forecast-ers—the International Energy Agency (IEA), the US Energy Information Administration (EIA), and OPEC—are in agree-ment about what to expect next year.

The boom in oil production—primarily from North American unconvention-als—should lead to another year of global surplus, with supply outstripping world demand. Global demand will actually rise next year, but at a lesser rate than non-OPEC oil supply. In addition to the US, supplies are expected to increase from Canada, Brazil, and Kazakhstan. ExxonMobil’s Kearl project will boost Canadian output, while the startup of the Kashagan project in the Caspian Sea should add 250,000 BOPD in production in Kazakhstan.

The IEA believes that non-OPEC output will rise by 1.3 million BOPD next year, annual growth that has occurred only once in the past 20 years. The largest increase will come from the US, with that country’s production rising 500,000 BOPD. In July, US crude production increased to 7.5 million BOPD, the highest monthly level of pro-duction since 1991. The EIA forecasts that US total crude oil production will average 7.4 million BOPD this year and 8.2 million BOPD in 2014.

Total global demand is forecast to rise 1.3 million BOPD next year, to more than 90 million BOPD, according to the IEA, with OPEC slightly less optimistic with a fore-cast of a 1 million BOPD rise. Global oil demand has grown approximately 7 million BOPD since 2005. OPEC member countries will meet in December to formalize strat-egy for 2014.

Meanwhile, OPEC is coming to grips with the US shale boom. At its meeting in July, OPEC ministers conceded that the world will need less of its crude even though world demand will grow at its healthiest pace since 2010. The organiza-tion said that demand for OPEC crude will fall by 300,000 BOPD to 29.6 million BOPD. Production from OPEC leader Saudi Arabia is healthy, as output has grown to historic levels.

Differences exist among these three major forecasts. The EIA is more optimis-tic about global demand and supply growth while OPEC is the most pessimistic. All three forecasters predict that OECD demand will decline, although at a slower rate, while non-OECD demand growth will continue to increase. China is something of a wild card. The EIA predicts a slight rise in Chinese demand growth next year to 389,000 BOPD from 360,000 BOPD this year. But OPEC sees that demand growth relatively flat. JPT

EDITORIAL COMMITTEESyed Ali—Chairperson, Technical Advisor,

SchlumbergerFrancisco J. Alhanati, Director, Exploration &

Production, C-FER TechnologiesMohammed Azeemuddin, Geomechanics and Pore

Pressure Team Lead, ChevronBaojun Bai, Associate Professor/Graduate Coordinate Petroleum Engineering, Missouri University of Science

and TechnologyIan G. Ball, Technical Director, Intecsea (UK)

Luciane Bonet, Reservoir Engineering Manager, Petrobras America

Paul D. Cameron, Senior Well Intervention Discipline Advisor, BP plc

Robert B. Carpenter, Sr. Advisor–Cementing, Chevron

Simon Chipperfield, Team Leader Central Gas Team/Gas Exploitation, Eastern Australia Development,

Santos Gerald R. Coulter, President, Coulter Energy International

Martin V. Crick, Chief Petroleum Engineer, Tullow Oil plc

Jose C. Cunha, Drilling Manager, Ecopetrol America.Alexandre Emerick, Reservoir Engineer,

Petrobras Research CenterMartyn J. Fear, General Manager – Drilling &

Completions,Husky EnergyNiall Fleming, Leading Advisor Well Productivity &

Stimulation, StatoilEmmanuel Garland, Special Advisor to the

HSE Vice President, TotalA.G. Guzman-Garcia, Engineer Advisor,

ExxonMobilRobert Harrison, Global Technical Head of Reservoir

Engineering, Senergy Oil & GasDelores J. Hinkle, Director, Corporate Reserves,

MarathonGeorge W. Hobbs, Director, Strategic ChemistryJohn Hudson, Senior Production Engineer, ShellGerd Kleemeyer, Head Integrated Geophysical

Services, Shell Global Solutions International BV Gregory Kubala, Global Chemistry Metier Manager,

Schlumberger Jesse C. Lee, Chemistry Technology Manager,

SchlumbergerCam Matthews, Director, New Technology Ventures,

C-FER TechnologiesCasey McDonough, Drilling Engineer,

Chesapeake EnergyStephane Menand, Managing Director,

DrillScan USJohn Misselbrook, Senior Advisor for Coiled Tubing,

Baker HughesBadrul H Mohamed Jan, Lecturer/Researcher,

University of MalayaAlvaro F. Negrao, Senior Drilling Advisor,

Woodside Energy (USA)Shauna G. Noonan, Staff Production Engineer,

ConocoPhillipsKaren E. Olson, Completion Expert,

Southwestern EnergyMichael L. Payne, Senior Advisor, BP plc

Mauricio P. Rebelo, Technical Services Manager, Petrobras America

John D. Rogers, Vice President of Operations, Fusion Petroleum TechnologiesJon Ruszka, Drilling Manager, Baker Hughes (Africa Region)

Hisham N. Saadawi, VP Engineering, ADCO (Abu Dhabi Co. Onshore Oil Opn.)

Jacques B. Salies, Drilling Manager, Queiroz Galvão E&P

Helio M. Santos, President, SafekickOtto L. Santos, Sênior Consultor, Petrobras

Luigi A Saputelli, Senior Production Modeling Advisor, Hess Corporation

Brian Skeels, Emerging Technologies Manager, FMC Technologies

Sally A. Thomas, Principal Engineer, Production Technology, ConocoPhillips

Win Thornton Global Projects Organization, BP plc

Erik Vikane Manager Petroleum Technology, StatoilScott Wilson, Senior Vice President,

Ryder Scott CompanyTo contact JPT’s editor, email [email protected].

CommentsSept.indd 14 8/12/13 2:45 PM


GUEST EDITORIAL

Bob Keiller became chief executive officer (CEO) of the John Wood Group in November 2012. Previously, he was CEO of Wood

Group PSN and CEO of Production Services Network before its acquisition by Wood Group. He has also served as chairman of the Offshore Contractors Association, the UK Helicopter Issues Task Group, the Entrepreneurial Exchange, and cochair of Oil and Gas UK. Awarded the Aberdeen Entrepreneur of the Year in 2006 and 2008, he was also named Scottish Businessman of the Year in 2007 and Grampian Industrialist of the Year in 2008. Keiller received a master of engineering degree from Heriot-Watt University and is a chartered engineer.

Most people who work in the oil and gas industry know what a “permit to work” is. A blue permit indicates that it covers “cold” work—work with no potential to create a naked flame, hot surface, spark, or explosion. Having a permit ensures that the job site is safe for the team to do its work, that the team understands the potential risks of the work it is planning to do, and that it agrees to put suitable controls in place.

I spoke recently at the Piper 25 Conference, a 3-day event held in Aberdeen to mark the 25th anniversary of the Piper Alpha disaster that killed 167 people on board the oil platform in the North Sea. On display at the conference was a copy of Cold Work Permit 23434. The tattered paper was found in the accommodation module that was recovered from the seabed. The permit was for the replacement of a relief valve on the B condensate pump. It was this work that was at the heart of the initial release and explosion when the operators tried to start the pump even though it was not ready. The rest, tragically, is history.

It begs an obvious question and a supplementary one: Could something similar happen again and, if so, can we do anything to reduce the chances of it happening?

The oil and gas industry has made huge advances in safety management over the past 25 years. The goal-setting regime, safety cases, and verification schemes have been hugely beneficial.

We have greater collaboration and everyone now talks about safety as being impor-tant and most people genuinely believe it. However, the industry is still experiencing too many serious events which, if we are unlucky, could easily result in another tragedy.

We are a global industry in which good practices are shared across our opera-tions. The loss of life in any country has to be as unacceptable as a tragedy on our own doorstep.

Over the past 25 years since Piper Alpha, there have been more than 25 multi-fatality accidents in our industry. In June, two people died in an accident on a gas platform in the Dutch sector of the North Sea. Last year, three died in an explosion in the Gulf of Mexico (GOM) and 11 died in the Deepwater Horizon explosion in the GOM in 2010.

Can we do anything to make these situations less likely? Are we controlling the risks to our people in a joined-up way?

Recommendation 67 of Lord Cullen’s Report on the Piper Alpha disaster called on the industry to institute common systems for alarms and warning lights. Unfortu-nately, at the time, the industry could not reach this position voluntarily and legisla-tion was needed to create new regulations.

Surely that would not happen today because we have a unified approach with strong, clear leadership across the industry that understands the benefit of common systems and approaches and are not hung up on insisting that only their corporate systems will do. We are happy to agree on common standards for survival training, we have a common system for tracking people traveling offshore, and we have agreed on standards for use of personal locator beacons on helicopter flights.

These are all good. But we are not so good at agreeing to common standards in other areas, such as work control, isolation standards, risk assessment, and safety

Creating a Common Safety CultureBob Keiller, CEO, Wood Group

GuestEdSept.indd 16 8/12/13 3:30 PM

17JPT • SEPTEMBER 2013

observation programs. We are good at creating guidelines, but are reluctant to make any hard-and-fast safety rules for the step change “safety club” because few clubs allow membership to choose which rules to follow.

Why not introduce a common per-mit to work? A common job safety assess-ment? Common observation programs? Common isolation standards? What a sig-nal it would send to the offshore work-force about our genuine commitment to their safety.

Who Gets the Learning?More contractor personnel get hurt off-shore than operator personnel because there are more of them and fewer work in offices or control rooms. So when an accident happens and a contract worker is injured, you might think that the con-tractor company has at least as much to learn as anyone else, yet often the com-pany does not hear about the accident straight away, is refused access to par-ticipate in the investigation, and does not see the findings unless the operator is faulting the contractor.

The right to be informed of any and all accidents, the right to participate in investigations, and the right to see all findings should be part of the industry’s standard contracting terms. We all have a legal duty to take care of our employ-

ees and a legal obligation to cooperate in ensuring the safety of others affected by our activities. So it is not unreasonable to check the work site where our staff may be working, yet many operators take offense at being asked to demonstrate workplace safety.

Leadership Is the KeySo what can we do about this?

Although we can have better sys-tems, more competent people, higher standards, and better training, the key and common ingredient is leadership.

There are hundreds of books on leadership and a thousand different models—each one has merits and many have evidence to support them. So if we cannot get a common idea of leadership, what is the chance of obtaining a com-mon idea of safety leadership?

Leadership shapes culture, culture shapes behavior, and poor behavior is the common factor that can undermine competent people, good design, and strong processes.

It comes down to three basic build-ing blocks.

Things you need to know. A safety lead-er needs to be informed about what is happening in the business, and be aware of any and all accidents and near miss-es. To know these things, you need to

ask and check—all the time. You need to know the bad news, the concerns, and the complaints and have a culture that does not filter these out.

You also need to know the risks faced by your people, as well as contrac-tors, subcontractors, vendors, and other specialists. You need to know that all of these people are competent. You need to know that risk controls are in place and are effective. And you also need to know that people will do the right thing in an emergency.

Things you need to say and not say. It is said that the primary role of leader-ship is about setting the tone. It is more than that; it is about repeatedly pro-viding clear and direct messages that reinforce a commitment to safety. Being clear is far from easy—messages need to be repeated, received, credible, and not drowned out or undermined.

Things you need to do and not do. Actions need to match the good words. People see actions—often they do not hear the words. If actions do not match the words, then credibility dis-appears in an instant. Safety leaders need to be aware that their actions, and sometimes their inactions, are visible and send a bigger message than all the words combined. JPT

GuestEdSept.indd 17 8/19/13 9:52 AM

TECHNOLOGY APPLICATIONS


Electrical Wellhead OutletAnTech Limited unveiled its new Type C, the smallest model in the company’s extensive range of wellhead outlets that continuously monitor downhole pres-sure and temperature in permanent completions (Fig. 1). The Type C uses a threaded wellhead connection in link-ing the downhole cable to the surface telemetry system and is attached to

the wellhead to provide a safe connec-tion between the cables and seal against downhole pressure. The configuration ensures that the integrity of the well-head is maintained and electrical con-nections are secure, even if the down-hole cable is flooded. The Type C uses pressure-testable cablehead technolo-gy that requires few connections to be made up. The Type C is certified for use in hazardous areas, meets with corro-sion standards, and has been success-fully pressure-tested in keeping with American Petroleum Institute require-ments. It operates to 15,000 psi and in temperatures as high as 160°C. The Type C is available in models that are compatible with single, dual, and tri-ple conductors, and can be supplied in ¼-in. configurations.◗◗ For additional information, visit

www.antech.co.uk/antech/product-list/wellhead-outlets.

Drilling-Fluid SystemBaker Hughes has announced the availability of its MPRESS drilling- fluid system, which can improve drill-ing economics by enabling operators to manage circulating pressure more efficiently (Fig. 2). The system allows operators to reduce their standpipe pressure and apply more horsepower to the bottomhole assembly and drill bit, thereby increasing rates of pene-tration and decreasing nonproductive time. MPRESS also reduces viscosity in the drillstring while optimizing viscos-ity in the annulus for more efficient cut-tings transport. The pressure saved in the drillstring can be used to increase flow rate, provide more power to motors and bits, and save wear and tear on sur-face equipment. The system features elevated ultralow-shear-rate viscosity and a shear-thinning rheological profile with a “rapid-set/easy-break” gel struc-

Chris Carpenter, JPT Technology Editor

Fig. 2—The MPRESS drilling-fluid system from Baker Hughes.

Fig. 1—AnTech’s Type C wellhead outlet.

TechAppsSept.indd 18 8/12/13 1:29 PM



ture that minimizes the cuttings in the vertical section of the wellbore settling into the curve during connections and trips. Both the elevated viscosity and the rapid-set gels help keep the well-

bore clean and minimize torque and drag associated with cuttings beds in the lateral section.◗◗ For additional information, visit

www.bakerhughes.com.

Silica TechnologyProduced Water Absorbents (PWA) has commercially launched its Osorb media technology, an organically modified sili-ca for the treatment of oilfield water and gas streams (Fig. 3). The silica medium is hydrophobic and does not absorb water, but can remove more than 99% of free, dispersed, and soluble hydrocarbons and toxic contaminants from water and gas streams. The technology is applied in both onshore and offshore applications for the purposes of discharge, chemical enhanced oil recovery, reinjection, ben-eficial reuse, prevention of membrane fouling, air-emission controls, and off-shore excursions. No permanent chemi-cal bonds are formed between the medi-um and the contaminants during these processes because the medium is both an adsorbent and an absorbent. This lack of permanent bonding enables the repeat-ed regeneration and reuse of the media while also recovering the captured con-taminants. Regeneration can be achieved by use of various processes that typical-ly maximize resources available on site, such as gaseous purge.◗◗ For additional information, visit

www.pwasystems.com.

Pressure SensorsHoneywell Sensing and Control has introduced two new additions to its Wing Union/Hammer Union line of pres-sure sensors, with potential applications in oil and gas drilling, mud pumps and mud logging, fracturing and cement-ing, acidizing, wellhead measurement, and standpipe stimulation. Model 425 is available in two accuracy levels, while the Model 427 provides a wide and shallow sensing port that facilitates an effective flow of more viscous media blends. Built on the Wing Union one-piece design with stainless-steel construction (Fig. 4), both models provide accurate and reli-able data for detection of small chang-es in pressure, allowing the operator to quickly adjust media flow pressure dur-ing drilling operations. This helps drill-ing operators optimize oil-withdrawal rates and profile potentially dangerous conditions to increase safety of drilling Fig. 4—The Model 425 and 427 pressure sensors from Honeywell.

Fig. 3—PWA’s Osorb silica floating in a flask after absorbing more than 99% of all dispersed oil in a produced-water sample.




personnel. Both models offer multiple electrical connections and are designed for quick field installation, offering resistance to torque stress at hammer-up with field-adjustable zero and span for reliable long-term performance. ◗◗ For additional information, visit

https://measurementsensors. honeywell.com.

Platform Supply VesselThe first of six Damen 3300 platform supply vessels (PSVs), the World Dia-mond, has been delivered to Norwe-gian offshore support company World Wide Supply (WWS). The 400-t-deck- capacity PSV 3300 is the result of exten-sive design work in close cooperation with the client and full tank testing

(Fig. 5). The World Diamond will be the first PSV in the new series to be deliv-ered to launching customer WWS (Nor-way). Damen’s current Offshore Series includes PSVs ranging from 1500 to 6500 deadweight tonnage; Fast Crew Suppliers from 19 to 67 m in length, fea-turing the slamming-reducing Sea Axe bow; Anchor-Handling Tug Suppliers with 75 to 200 t of bollard pull; the Offshore Heavy-Lift Vessel 1800; the Ro-Ro Deep Dredge; various standby and multipurpose support vessels; and the new Damen Offshore Carrier 7500, featuring a 2300-m2 deck area.◗◗ For additional information, visit

www.damen.com.

Telescopic GangwayOffshore Solutions BV has released its Offshore Access System, a 21-m, hydraulically operated telescopic gang - way fitted with an active heave- compensation system (Fig. 6). It is the only heave-compensated gangway sys-tem that can maintain a permanent con-nection. The gangway comprises a ped-estal, operator cabin, telescopic boom, and gripper platform. With continu-

Fig. 5—The World Diamond PSV 3300 from Damen’s Offshore Series of vessels.

Fig. 6—The Offshore Access System telescopic gangway from Offshore Solutions BV.

TechAppsSept.indd 22 8/14/13 7:18 AM


ous 24-hour connection and operating capability, it incorporates a motion- reference unit in its active hydraulic sys-tem, which, when engaged, maintains the walkway tip at a constant height relative to the horizon. This allows the gangway to be connected safely to a fixed offshore installation in unstable sea conditions when mounted onboard a suitable vessel. Once connected, the heave compensation is disengaged and the gangway is allowed to float between the vessel and the installation. The walk-way is robustly connected and automati-cally compensates for the six movement planes of the vessel motion. ◗◗ For additional information, visit

www.offshore-solutions.nl/en/.

Logging-While-Drilling ServiceHalliburton has introduced its XBAT azimuthal sonic and ultrasonic logging-while-drilling (LWD) service (Fig. 7). The XBAT LWD service delivers accu-rate acoustic measurements in a wide range of formations through sensors and electronics that are less sensitive to drilling noise and have a wide frequency response. The result is a greater signal/noise ratio that enables better measure-ments even in noisy drilling environ-ments and poor hole conditions. The XBAT LWD service has delivered accu-rate measurements in formations across

the globe and has been tested extensive-ly in the challenging environments of the North Sea and the Gulf of Mexico. The XBAT LWD service uses four dis-crete transmitters and four azimuthal-ly spaced receiver arrays. Each receiver is sensitive across a broad range of fre-quencies and is isolated from the col-lar to eliminate bit and mud-circulation noise. Using results from a broad range of frequencies, the XBAT LWD service provides a 3D image of the velocities around the wellbore. ◗◗ For additional information, visit

www.halliburton.com.

Swellable ElastomerTAM International has launched a new line of FastSwell elastomers (Fig. 8). The elastomers provide a fast, con-trolled swell time at lower temperatures and high salinities. The FastSwell prod-uct line was developed specifically for current challenging water-swell condi-tions in the Permian Basin and Rus-sian fracture markets, but both water-swell and oil-swell elastomers are now available worldwide. The elastomers perform well for fracture applications between 80 and 120°F. The technolo-gy reduces production delays for well operators working in low bottomhole temperatures because it allows hydrau-lic-fracturing operations and comple-

tion activities to commence more quick-ly. FastSwell does not rely on protective coatings to prevent premature swell-ing during the trip in the hole; reliable prediction of swell times is designed into the numerous compounds devel-oped specifically for various global well-environment applications. ◗◗ For additional information, visit

www.tamintl.com.

Metal-Capturing Tool for WellboresThe 5D Oilfield Magnetics Open Hole Net (OHN) catches metal dropped into wellbores (wrenches, chain, shackles, bolts, nuts, washers, tong dies, and hand tools). The OHN also catches metal coming out of the wellbore and allows captured materials to be retrieved or measured (Fig. 9). The OHN is a system of specially designed magnets that take the place of the bell nipple when the dis-charge is built into the unit. The system is designed to take the magnetic field out of the internal diameter of the OHN when operations that could be affected by a strong magnetic field, such as mea-surement-while-drilling, LWD, or wire-line logging tools, are executed in a well program. The OHN is installed by the rig crew, and no power source or operator is required. JPT◗◗ For additional information, visit

www.5doilfieldmagnetics.com.

Fig. 8—The FastSwell elastomer from TAM International.Fig. 9—5D Oilfield Magnetics’ Open Hole Net metal-capturing device.

Fig. 7—Halliburton’s XBAT LWD service.


TECHNOLOGY UPDATE


The growing desire of offshore operators to speed up subsea field development while reducing costs has fostered many compelling innovations. Among those systems under development to meet this demand, and one with broad applica-tions, is a subsea storage unit (SSU) creat-ed by Kongsberg Oil & Gas Technologies.

The SSU employs the new concept of a “flexible bag” protected by a dome for oil storage on the seafloor (Fig. 1). Depending on field conditions, the dome can be made of concrete, fiberglass, or steel. The system offers oil compa-nies a safer, more cost-effective method of developing subsea fields in extreme weather zones or in the Arctic where ice floes are prevalent. The SSU is also being qualified for extended well testing (Fig. 2) and early production startup, and it may enhance the economics of fields with insufficient reserves to support full

field development. Furthermore, the SSU could be used in place of subsea storage cells, fixed platforms, floating storage units (FSUs), and pipelines.

“It is an alternative to existing stor-age facilities and could also potentially commercialize the development of mar-ginal fields,” said Astrid Rusås Kristof-fersen, a subsea systems product and technology manager at Kongsberg. “The [SSU] will increase profitability of mar-ginal fields, because the oil can be stored subsea. And then, using small shuttle tankers for more frequent offloading will precipitate the cash flow and reduce operational costs.”

Ideally, two or more SSUs could be used to maximize the allowable output volume that could be uploaded into a tanker. As production increases, SSUs could be added to the cluster. Kongsberg is considering standardizing the dimen-

sions of the SSU to fit different needs, with the largest version on the drawing board being 131 ft (40 m) in diameter with a capacity of 120,000 bbl of oil.

Subsea storage technology has been used before in limited applications, but never has the design used a collapsible bag to store the oil. The bag is partly made of a polyester woven yarn that is coated with an impermeable layer on both sides to eliminate the possibility of seawater and oil mixing. Were that to happen, an emulsion layer could form, leading to bacterial growth that could cause corrosive damage inside steel pipe-lines and valves.

Subsea Storage Unit OperationOpenings at the base of the SSU allow seawater to flow in and equalize the pressure. So there is no need to design against pressure and the unit can be

Storing Oil on the Sea Bottom to Improve the Bottom LineTrent Jacobs, JPT Technology Writer

Fig. 1—The technology being developed by Kongsberg uses a subsea storage unit with a flexible bag inside a protective dome to store oil on the seabed at any depth.

Fig. 2—A computer rendering shows how three subsea storage units could store oil during an extended well test involving a jackup rig and shuttle tanker.

TechUpdateSept_Art1.indd 24 8/12/13 1:03 PM

TECHNOLOGY UPDATE


deployed to any water depth. The bag can then expand and contract as the vol-ume of oil inside increases and decreas-es. Depending on the type of soil, a com-bination of weights, suction anchors, and piles could be used to secure the SSU to the seabed.

The SSU’s intake valves allow the product to flow inside, and once the bag is filled to capacity, the oil can be trans-ported to a tanker through a standard flowline and offloading system. If an operator wishes to use the SSU for chem-ical storage, the unit would work in the same fashion. Only the source of fluids entering the SSU and the final export flow destination would differ.

If the internal sensors detect a leak inside the bag, they will shut off the intake valves while alerting the opera-tor to the problem. The SSU’s design cre-ates a “double barrier” that protects the environment from exposure to hydrocar-bons. “In case the bag should rupture, the outer dome is capable of collecting all the source fluids, preventing spillage into the sea,” Kristoffersen said.

With the dome serving as the sec-ond containment layer, the leaked oil can be safely extracted to a sister SSU or discharged to a shuttle tanker on the surface. A removable hatch atop the SSU provides access to the bag and allows easy retraction when replacing the bag.

The SSU’s weight will depend on field conditions and hydrostatic uplift forces from the stored oil and other flu-ids. In its base configuration, the SSU is designed to float so that a wide vari-

ety of vessels can perform the instal-lation work, which eliminates the need for heavy lift vessels.

Expected Service LifeThe dome and shell of the SSU will typi-cally have a service life of 25 years and the bag is being qualified for a life span of 10 years. Kongsberg is looking for ways to extend the bag’s life.

The inspiration for the SSU arose from Statoil’s quest to eliminate the need for surface production systems and put the entire “factory floor” directly on the seabed. “This is one piece of that puzzle,” said Kristoffersen, who added that the SSU also provides a measure of safety for operators who are aggressively seeking new ways to eliminate hazards.

“Currently a lot of oil is stored on FSUs and [floating production, storage, and offloading units], and there is always the risk of collisions with a tandem-load-ing shuttle tanker. So by storing it subsea, you eliminate that risk,” he said.

During a fire or an onboard explo-sion, the oil stored in the SSU will not continue to feed the fire. Additionally, if an operator uses several SSUs instead of a floating or fixed storage facility, operat-ing costs will be greatly reduced because subsea storage removes the need for a manned crew or helicopters and boats that provide supplies and transport. Instead, the SSU can be integrated into a remotely controlled subsea production system or a topside production facility that removes the water and gas before transferring the raw crude into the stor-age unit.

System FlexibilityThe flexibility to suit the operator’s field needs is another advantage of the SSU over traditional storage systems because each SSU can be picked up from the sea-floor and be redeployed to another field.

If used for extended well testing, the SSU provides another economic incen-tive by allowing the operator to collect first oil rather than “burning off ” the product. Compared with traditional sur-face storage, the SSU in operation has a considerably lower environmental foot-print because the system requires no rou-tine vessel or aircraft support that would emit greenhouse gases.

The SSU technology is being devel-oped for use in the North Sea and is supported by Norwegian oil com panies Statoil, Lundin Petroleum, and Det Norske Oljeselskap, and by the Norwe-gian Research Council. Kongsberg will start laboratory tests in 2014 after which the company plans to begin a pilot pro-gram that would include the subsea installation of a full-scale SSU.

The SSU is being designed to meet the requirements of Norway’s offshore regulations and is to be qualified for the North Sea. However, Kristoffersen said, “The SSU is providing a global solution for storing stabilized oil on the seabed.”

Because the SSU is a new design, Kongsberg is offering studies to show the feasibility and concept of subsea stor-age for specific fields, including the stud-ies of risers, subsea manifold systems, interconnecting pipes, and the control system logic required for SSU operation and process integration with specific off-shore infrastructure. JPT

TechUpdateSept_Art1.indd 26 8/19/13 10:46 AM

TECHNOLOGY UPDATE


Underreamed wells are among the tough-est challenges to using a centralizer, a device that keeps the casing or liner in the center of a wellbore. Underreaming, the technique of enlarging of a wellbore beyond its originally drilled size, is a drilling method widely used to increase the openhole size, which may be required for various reasons.

Some well planners believe it is saf-est to drill unknown shallow formations with a small diameter bit and enlarge the pilot hole if no gas is encountered. Underreaming may also be performed if a small additional amount of annular space is desired, for example, if a liner must be run to protect against surge pressures.

A fundamental problem with under-reamed wells is achieving effective casing

centralization in the underreamed sec-tion. The job of the centralizer is to center the casing to improve run in hole (RIH), allow easier pipe rotation, and to enable the cement column to circulate freely around the tubular and produce a robust cement seal to ensure zonal isolation.

Mud displacement is vital to achiev-ing a good cement bond. The more cen-tral the pipe, the more efficient the mud displacement will be. In deviated and horizontal wells, if the tubular is not cen-tralized, it will lie along the low side of the borehole and make cement circula-tion and the achievement of a uniform cement sheath difficult.

Poor centralization can also impair the cement bond by causing channeling, which can lead to various live annulus

problems. Like any fluid, cement will take the easiest route in the annulus, and this can result in an inadequate seal if the cas-ing or liner is not centralized. In addition, if the annular clearance is restricted in some sections, backpressure may result that requires a much reduced flow rate during cementation to avoid fracturing the formation and thereby losing fluid.

Offset Bow CentralizerThe Uros offset bow centralizer devel-oped by Centek is designed for use in underreamed or washed-out well sec-tions. The device significantly reduces initial insertion forces and drag when running through previously set casing. Once through this compressed stage, the offset bow centralizer will revert to its designed outer diameter in the open hole and thus maximize standoff without addi-tional drag. The device achieves a reduc-tion in drag compared with other central-izers because of its patented bow design, in which the high points of the bows are offset alternately without reducing the strength of the unit or its capacity to cen-tralize the casing in the open hole.

An oilfield service and product sup-plier operating offshore Norway has specified the use of the offset bow cen-tralizer in underreamed and deviat-ed wells since August 2011. Even when using two centralizers per pipe joint, the company has consistently been able to reach target depth while maintaining the desired standoff in the open hole. The company is running the device in several fields and has expanded its use to normal wells, because of the fluid and cement displacement benefits that it allows.

Offset bow centralizers are increas-ingly used in Norwegian offshore well

Offset Bow Centralizers MeetUnderreamed Well Challenges Marius Boncutiu, SPE, and Richard Berry, SPE, Centek Group

Fig. 1—Undamaged centralizers were pulled twice from a well at 40 m above total depth and then run successfully for a third time to the target level.

TechUpdateSept_Art2.indd 28 8/12/13 1:05 PM


operations. These wells often have a high risk of washed-out sections, i.e., open-hole sections that are larger than the original hole size, which are generally caused by soft or unconsolidated forma-tions. However, even in gauge holes, off-set bow centralizers are used to ensure high standoff.

Case StudiesA well operator offshore Norway ran 7-in.×9½-in. offset bow centralizers through 9⅝-in. 53.5-lbm/ft casing into an 8½-in. open hole with a total depth of 3600 m. Twice the operation reached a depth of 3560 m before it was necessary to pull the liner. Both times the liner was partially rotated in the open hole on the way in and was rotated for about 12 hours at 20 rev/min in the cased hole on the way out. The centralizers also had to be run through a whipstock window.

Each time after pulling the liner, the drilling and cement teams inspected all the centralizers and stop collars (Fig. 1). The only visible damage was some bend-ing of the set screw sockets. The opera-tor was able to run the same centraliz-ers again and eventually install them at target depth. The offset bow centralizers were run through the whipstock window on five occasions without snagging or packing out on the edges. By comparison, an oversized conventional bow spring centralizer would have exhibited consid-erably more drag during pullout.

The offset bow centralizers are also being used in various Latin Ameri-can operations. In an Ecuadorean well, 7-in.×9⅞-in. centralizers were run through previously set 8.535-in. inside diameter casing into a 10.4-in. aver-age diameter open hole. The installed centralizers achieved a standoff higher than the customer’s requirement of 70% along the target zone. In addition, there was less risk of differential sticking, an even annular flow of fluid, and a good well cleanout, with an improved cement job ultimately achieved. The centraliza-tion was defined using an analysis of openhole logs, standoff calculations, and liner tally. Centralizers were distributed two per joint along M1 sandstone.

It is necessary to understand the insertion forces and the cumulative run-ning forces, as both affect the RIH per-formance because the bows are squeezed while passing through the smaller inner diameter of the previously set casing. If needed, the first few joints can be pre-filled with mud to increase the string’s weight and enable it to be run in under its own weight from the beginning when less weight is present. This makes it possible to overcome the initial inser-tion and running forces without push-ing the pipe.

In the Ecuador case, when all the casing was run and the liner hang-er was installed, the pickup weight was 100,000 lbf and the slackoff weight was 70,000 lbf, which indicated 30,000 lbf of drag. Fig. 2 shows the drag calculation results, which are close to the real val-ues observed while running the casing. In this case, the running force for each centralizer was approximately 1,000 lbf.

There was no restriction while run-ning the liner through the open hole, and the bottom was reached without problems. During circulation, there was no indication of debris accumulation

caused by drag. According to the circula-tion parameters, the well showed a good cleanout. By having acceptable drag con-ditions when passing through the previ-ously set casing, low drag conditions in the open hole, and maximizing standoff in an enlarged annulus, the offset bow centralizers proved to be a major aid to reaching bottom and obtaining a good cement job in the Ecuadorean well.

Summary of BenefitsOffset bow centralizers result in great-ly reduced torque and drag losses, and because they are heat treated, abrasive wear caused by running to depth and rotating the tubular is eliminated. Reduc-ing torque ensures that casings can be rotated without wear in cased and open holes at deeper levels than would oth-erwise be possible. The ability to rotate a pipe can also greatly assist in mud removal. Typically, a rotational speed of 6 to 10 rev/min is all that is needed.

The centralizers are individually designed to fit each wellbore, rather than generally designed for specified gauge holes. Secure stop collars prevent cen-tralizer movement on run in or pullout.

Fig. 2—The drag calculation results were close to the real values while running the casing.

Liner Production: Drag

Cas

ing

Sh

oe

Mea

sure

d D

epth

, m

Hookload, lbf

40,000

0

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

60,000 80,000 100,000

Running by itsown weight 17,150 lbf

70,000 lbfSlackoff

96,000 lbfPickupTraveling Assembly

Weight

Slackoff weight, lbf

Pickup weight, lbf

Static weight, lbf


TECHNOLOGY UPDATE


The choice of a centralizer depends on a number of factors such as the expect-ed flow by area, the desired standoff, the strength and geometry of the formation, the required zonal isolation, the central-izer flexibility needed to traverse known

formations, and the estimated start and running forces.

Ensuring a lasting, effective annular seal in the wellbore is vital to maintain-ing oil and gas production. Preventing water inflow is extremely important and

requires good zonal isolation. Achieving a long-term annular seal is difficult, espe-cially in long extended reach wells. The use of offset bow centralizers can aid the cementing process in underreamed and conventional extended reach wells. JPT


2014 SPE President

Jeff SpathJohn Donnelly, JPT Editor

Jeff Spath is a member

of the Schlumberger

executive management

team as vice president

of industry affairs and is

the 2014 SPE President.

He will take office during

the 2013 SPE Annual

Technical Conference and

Exhibition, to be held

30 September–2 October

in New Orleans.

PresInterview.indd 32 8/13/13 9:24 AM


What are your goals as SPE president?One goal would be to further globalize the Society. There is no doubt that SPE has made huge strides internationally from what was once a predominantly North American member soci-ety in the 1970s and 1980s. Today, more than half of our mem-bers reside outside North America. We have to continue to fol-low the upstream oil and gas business to the new frontiers, the new basins, and the new regions of exploration such as Green-land, east Africa, and the Caspian. Not just for the sake of mem-ber growth, but to make SPE more local and more relevant by adding professional sections and student chapters so critical to achieving success—both for industry and for individuals—in these new regions.

Secondly, we need to increase the degree to which SPE engages and collaborates with other organizations. We all accept that reservoirs are becoming more challenging to dis-cover and produce. They are smaller, more complex, and they exist in increasingly hostile terrains under more difficult tem-peratures and pressures. Not to mention the challenges created by nano-perm shales and ultraheavy oil.

No single company, university, or government has all the expertise required. So we need to collaborate in all directions, including with other industries, such as the aerospace, automo-bile, and medical industries. SPE has an incredible reputation as a professional society and I want to capitalize on this reputation by taking the lead in fostering collaboration with other indus-tries, other societies—which we are already doing quite well—and with trade associations.

Also, I hope members are aware of the new SPE Strategic Plan that the SPE Board of Directors put together under the

guidance of my two predecessors. I am in the fortunate posi-tion now to oversee the implementation of this strategy that will further grow and strengthen SPE, and this will occupy much of my time.

What is the best way for SPE to continue to pursue globalization?Historically, SPE has followed the industry. After a significant number of operators and service companies have located in a region and universities have staffed up, SPE establishes a pres-ence. What I would like to do in places such as east Africa and in Myanmar, for example, is to be there, not necessarily first, but in parallel with the building of the industry.

Myanmar is a great example of a country in which SPE can bring significant value to individuals and to companies both, proactively, as they begin upstream development. Trade sanc-tions have just been removed, and Myanmar has had huge, very successful lease sales recently with operators such as Chevron, Petronas, PTTEP, Total, and others entering the mix.

I had an interesting experience on my last visit there when I toured the technical universities, recently reopened, after decades of being closed by the government. Schlumberger sup-ports universities around the globe by donating computers, software, bandwidth, etc., and so I offered these things but they said, “No, no, we need buildings, we need faculty.” They don’t even have buildings and faculty and are trying to start a petro-leum engineering program. This is where SPE should be—on the ground, early, where the operators and service companies are going and initiating new operations, disseminating the technology, and sharing the expertise.

Previously, he was president of the Schlumberger Reservoir Management Group and was president of Data and Consulting Services. He began his career with Flopetrol-Johnston Schlumberger as a field engineer conducting well tests onshore and offshore Louisiana and has worked for 30 years in various global positions in reservoir engineering, research, and management.

Spath is a recognized leader in the development and application of reservoir engineering and production enhancement techniques, including well testing, reservoir simulation, and nodal analysis. He is the author or coauthor of nearly 30 peer-reviewed publications and holds 14 patents.

An SPE member since 1983, Spath has served on many SPE committees and in many sections around the world. He was a Distinguished Lecturer during 1999–2000 and served as Technical Director of Management and Information during 2005–2008. He was elected an SPE Distinguished Member in 2011. Spath also currently serves on the Management Committee of the International Association of Oil & Gas Producers; the petroleum engineering advisory boards at Texas A&M University, the Colorado School of Mines, and the Natural Petroleum Council; and on the United Nations Global Energy Board.

Spath earned BS and MS degrees in petroleum engineering from Texas A&M University and a PhD degree in reservoir engineering from the Mining University of Leoben in Austria.


SPE PRESIDENT’S INTERVIEW


You mentioned the importance of the SPE Strategic Plan. What does it stress?The new plan refocuses the Society on what will be its most important functions over the next several years while reinforc-ing its mission and vision (see article on the SPE Strategic Plan beginning on Page 42). First, let me say that the strategy is a verification of our original and fundamental purpose—that of serving our members in the dissemination of quality, trusted technical information. To this end, members can expect to see additional methods of obtaining information about technology, through online journals, mobile devices, and other means.

Beyond this, though, there are a few specific strategic intents that will be important to ensuring the continued suc-cess of the industry, our profession, and SPE. One of my per-sonal favorites is the strategic intent of increasing the attrac-tion and retention of petroleum engineering faculty. The short-age of faculty at petroleum engineering schools is having a significant effect on the growth of our industry and, by cor-relation, our Society. Universities and industry both recog-nize this, and SPE is in an opportune position to help coordi-nate a solution. This issue is, to a certain extent, global, and is

particularly challenging in North America. It does no good to attract more young people to our profession and then accept less than 10% of petroleum engineering applicants due to lack of sufficient faculty.

SPE has spent a lot of time and effort—well-spent time and effort—going in to secondary schools to educate teachers and students on the wonders of our industry. So, on the one hand, we are encouraging all of these young bright students to enter our profession, but then we have to turn them down at the uni-versity level because we do not have enough faculty.

Only two countries graduate more petroleum engineers than they can employ: Venezuela and China. Everywhere else in the world, the industry is screaming for more petroleum engi-neering graduates. And the reason there are not more petro-leum engineering graduates is not a lack of people who want to be petroleum engineers, but because we do not have enough people to teach them.

Many companies hire mechanical engineers, electrical engi-neers, chemical engineers, and civil engineers and turn them into petroleum engineers through internal training. The indus-try would love to hire 100% petroleum engineers but it can’t

because they are not there. I have worked with a lot of university deans in trying to solve this problem and I believe it is solvable. But what is happening now is that you have Schlumberger trying to solve it with Texas A&M, Chevron trying to solve it with the University of Southern California, and so on. There is a lack of coordination. Coordination will be the role of SPE.

If you have a choice between being a teacher or working for an operator or service company that does really interesting work and pays a higher salary, you might choose that company over teaching.That is the crux of the problem. Like nowhere else in the world, US universities graduate PhDs but don’t keep them. They all go to industry. Or they go back to their country of origin.

A possible solution, and where SPE could help, is to take the 50-plus-year-old employees that do not have a PhD and put them into the universities as they finish their careers. I have worked with the deans at Texas A&M, the University of Texas, and the Colorado School of Mines and convinced them that they need to drop the PhD requirement for teaching undergraduate education. If a petrophysicist, for example, has been interpret-ing well logs for 35 years, he or she can probably teach under-graduates how to interpret well logs. We call them professors of practice.

Our company has taken another step along that path with a program called Schlumberger Professor Emeritus. We just did this for Colorado School of Mines. We took a world-class petro-physicist who was 60 years old and loved teaching. We kept him on our payroll to simplify benefits and he teaches at the univer-sity, which reimburses us 50% of his salary. We win because we want him there readying students for hire and he is a good ambassador for our company. The university wins because it is getting for half price a world-class petrophysicist who has inter-preted logs and geologies all around the world.

The only way to make a program such as this work is to do it in volume and that is how SPE can help, by coordinating such a program. This is a passion of mine, and it happens to be part of the strategic plan.

How will individual members be affected by the strategic plan?One of its emphases will be the bread and butter of SPE, which is the dissemination of technical information. We have identified ways SPE can be more relevant to members, such as bringing technology to people on the go. That is another element of the plan that I have a personal passion for: knowledge building and capability development. SPE will continue to provide options in training and competency assessment in an effort to reduce the time to autonomous decision making—one of the banes of our industry.

Two things cut horizontally across everything SPE does—technical quality and volunteerism. Volunteerism originally was one of the intents of the strategic plan, but the board con-cluded that it does not really fit as a strategic intent because

“Only two countries graduate more petroleum engineers than they can employ: Venezuela and China. Everywhere else in the world, the industry is screaming for more petroleum engineering graduates.”




volunteerism is part and parcel of everything SPE does. But one thing members around the world will notice about the strategic plan throughout is the renewed focus on volunteerism.

SPE is going to improve the volunteer recognition pro-gram, and we are going to help industry professionals volun-teer by helping with some administrative details that volun-teers deal with. Here is a great example from west Texas: when a small section wants to have an SPE Distinguished Lecturer come speak, someone from the section has to volunteer time to book a hotel room, make sure somebody picks the lecturer up at the airport, etc. We need to make better use of our volun-teers’ time and to support them so that they can add the most value to SPE.

Volunteerism is fundamental to our success, so we want to develop ways to improve volunteerism. We need to continually re-emphasize volunteerism because people are getting busier and busier and the volunteers that SPE traditionally relies on outside of young professionals are mid-career employees.

Engineers and managers both are doing more with less. I am not saying it was ever easy to balance workload, family, and volunteering, but it seems to me that the workload for many has dramatically increased. Mid-career professionals do the bulk of the volunteering today. Unfortunately, mid-careers are the exact demographic that is being challenged by the big

crew change. I have talked to members of operating companies who used to be responsible for 10 wells in the Permian Basin in Texas and now they are responsible for 100 wells in the Perm-ian and three new wells being drilled in the Gulf of Mexico. And you want them to volunteer? I mean, the guy hasn’t seen his kids in 2 weeks. It is up to SPE to think of ways to help mem-bers volunteer, such as reducing the burden of administrative tasks associated with reviewing technical papers or setting up Distinguished Lecturer tours. We need to emphasize the value of volunteering and get better at recognizing the effort.

What else should SPE emphasize in the near term?If SPE is to continue to grow as rapidly as it has in the past decade, the organization needs to better emphasize the advan-tages of being a member, and here I am talking simply about marketing what it can provide, both to existing and potential members. I have talked with members who have never been to the SPE website and seen the valuable links and information it provides. One of the most valuable assets the Society offers, the OnePetro library of 150,000 technical papers, is never accessed by some members.

Perhaps one of the most important initiatives SPE has embarked on fairly recently, and one in which we must increase our emphasis, is educating the public about our industry and, more importantly, our profession. We need to proactively, hon-estly, factually, rationally, openly, and not defensively discuss the good our industry brings to society, and SPE must be the trusted, independent source of facts around issues that worry the public. This theme of energy education, now profession-ally delivered through the Energy4Me initiative, is essential to SPE’s mission and I will build on the work of my predecessors in this effort.

What is the best way to educate the public about energy?Let me start by saying we got off on the wrong foot. When the movies came out about hydraulic fracturing and the rhetoric got hot and heavy, what did the oil and gas industry do? We, as we typically do as engineers, said, “That’s not right, here are the facts, you guys are wrong,” and we got defensive. And guess what? They found one well out of a million in Pennsylvania somewhere, which for completely different reasons, was leak-ing gas. And critics said, “Engineers, you’re not so smart. Here is an example.” So we have to level with the public. We have to agree with them, first of all, that there are potential hazards involved in producing oil and gas, as with any form of energy. And we have to prove to them that we are addressing those potential hazards.

There is a consortium of companies—including Schlum-berger, Halliburton, Baker Hughes, the other pressure pump-ers, and the operators—that are involved in an initiative called FracFocus, a website whose primary purpose is to provide the public access to information on chemicals used for hydraulic fracturing in their region. For example, a service company will go out and take a baseline measurement of methane, noise,




CO2 in the atmosphere, and any groundwater contaminants in the area. Then after the well is fractured, the same measure-ments are taken and the before-and-after results are published along with details about exactly what was pumped, chemical by chemical. A landowner, an environmentalist, or whomever can go to this website and get facts. So that is one way that we have disseminated factual information, and it is working. This has been so successful in the US that the International Association of Oil & Gas Producers, of which I am on the board, is doing something similar for Europe and elsewhere.

Are there other ways in which SPE can become more valuable to the industry?SPE has an extraordinary record of adding value to its mem-bers and to our industry in general; I doubt anyone would ques-tion that. This value will increase as our services and our global footprint continue to grow. SPE has the ability and opportuni-ty to help the industry as a whole by leveraging the strengths of its global reach, its more than 110,000 members, its tech-nology library, its independence, and its financial strength to achieve solutions to significant issues that may not be possible

to achieve by companies working alone, or by individual com-panies working with individual universities. Solving the fac-ulty shortage problem I mentioned earlier is one example of an industry problem that SPE can work across companies and across universities to mitigate.

And now I come to my central point on how SPE can become more valuable to the industry: It is the coordination of solving complex technology challenges through integration and collaboration.

By providing seminal, member-written white papers and providing the forum to showcase technical challenges and shar-ing potential solutions through the new Summit program, SPE can facilitate and accelerate the solving of industrywide techni-cal challenges. Each individual company can do that, or SPE can pave the way and coordinate the collaboration.

We are already adding significant value around integration by partnering with AAPG and SEG, for example, in various con-ferences and workshops to facilitate the bringing together of ideas, domains, and data. The feedback on these types of joint conferences has been very positive so we need to think about how to expand this. A great example is the Unconventional

Resources Technology Conference recently held in Denver. We cohosted this with AAPG and SEG because we know that the understanding of shale gas requires geologists, geophysicists, and engineers. In the future, we need to also invite geochemists and mathematicians.

How does collaboration benefit the oil and gas industry?As I mentioned before, the technical challenges we face today are often too difficult for any one organization to solve. Take the challenge of dramatically improving recovery factors, for example. Schlumberger has gotten serious in improving EOR techniques and measurements. However, while we are really good at measurements and understanding the subsurface, we do not possess the best chemistry labs in the business. So we partnered with Shell. Now, neither Schlumberger nor Shell has world-class imaging at a nanoparticle level, so we partnered with Massachusetts Institute of Technology, who does. We now have a three-pronged alliance with seven successful EOR research projects.

This is the value of collaboration. And of course it doesn’t need to end with collaboration within our industry. There are a lot of exciting developments happening outside of the E&P world that can have a huge impact on our business—from nano-technology to advanced robotics. As disruptive technologies evolve in other industries, we need to get smarter and quicker at adopting them into our industry. To a certain degree it requires a culture shift, and SPE can lead the way by fostering and coor-dinating the necessary relationships.

Can SPE continue to grow at the same pace that it has for the past few years?SPE has doubled membership in the past 10 years, and it can repeat this in another 10. There are two modes of growth. One is old-fashioned geographical expansion, where you grow your footprint in areas that are emerging. Places such as the Arctic, east Africa, Greenland, Myanmar—those are places in which we have not yet stepped foot.

A second mode of growth is where SPE has a presence but has yet to achieve the level of acceptance desired. One is Mexi-co and another is Russia. In Russia, I have already talked to the heads of Lukoil, Rosneft, and Gazprom and received positive feedback. We need to follow up now with the employees. Anoth-er area for growth, of course, is China. There are obstacles in language and in culture but we are solving these.

How will your career experience inform your presidency?To my knowledge, there is not a job description for being SPE president, nor a list of required qualifications, but I would like to think I am well prepared, and naturally hope my peers will agree. Two strengths I have that I feel will serve me well are a strong technical background and a varied, global career that has allowed me to work among many different cultures, value systems, business philosophies, and operating environments. One advantage I think I have from working for a global ser-

“Now I come to my central point on how SPE can become more valuable to the industry: It is the coordination of solving complex technology challenges through integration and collaboration.”




vice company for 30 years is the experience of interacting with all walks of the upstream life: from the largest IOCs and NOCs to the smallest independents. Finally, while I have worked for the same company my entire career, I have held positions from field engineer to salesman, from R&D to executive man-agement, so I think I can relate to people in various parts of the business.

So this gives me the breadth of understanding of how Anadarko, for example, works differently than Petrobras. And they both work differently than, say, ExxonMobil. Each of these groups of companies, not to mention each individual compa-ny, has a unique culture and I have seen it in practice. I know, for example, there are companies that just love SPE and they encourage their employees to write papers and go to confer-ences and travel halfway around the world for an SPE training course, because they know it will be worthwhile. And I have seen the opposite, where a company I will not mention recent-ly told me, “We don’t need SPE.” There is a spectrum out there and I think my experience in knowing how different companies and different cultures extract value from SPE differently will be an advantage.

Where do you see technology taking the industry in the next 5 or 10 years?Quite a few exciting developments are going on now in the industry. If I had to pick one or two that I think are most promis-ing, the recent advances in drilling, specifically around rig auto-mation, would be among the top in terms of improving our effi-ciency, safety, and bringing overall well costs down. The combi-nation of a dramatic increase in measurements along the drill-string and bottomhole assembly with computerization (thus optimization) on the rig floor and the designed integration of rotary steerable motors with the optimal bit and the optimal fluids is creating a huge impact on the operator’s bottom line.

A second growing trend in the industry addresses the integration of disparate measurements and data to reduce uncertainty and manage risk. This is not a new concept by any means, but the extent to which we are now combining seemingly unrelated data from different domains is making the industry much more confident in our subsurface inter-pretations and improving our ability to optimize produc-tion and maximize ultimate recovery. Think about the recent developments made in geomechanics, for example. Today, we



are taking advanced, in-situ measurements of geomechani-cal properties and routinely integrating them into every-thing we do; a decade ago, that was unheard of by many. Who thought 10 years ago that we would be integrating seismic data—acquired, processed, and interpreted while drilling—to guide the bit around hazards to the most productive part of the reservoir? Or to help us understand fracture propa-gation in shale? Integration is one trend we will definitely see continuing.

You have written quite a few technical papers during your career. What is the value of writing technical papers, for the individual, the company, and the industry?It benefits all three. Fundamentally, a good engineer should be a good writer; you have to be able to express your thoughts. Writing technical papers enriches an individual’s career. At Sch-lumberger, it isn’t just encouraged, it isn’t just rewarded, it’s a requirement for promotion. We have a formal technical ladder, like a lot of companies, and if you want to go from one rung on that ladder to the next, there is a concrete list of criteria. One of them is how many technical papers the person has written. So if

somebody comes to me and says, “I think I am ready to become an advisor,” I will say, “Have you published 10 SPE papers?” And they might say, “No, but I have written nine,” and I will say, “OK, come see me when you get that next one and we will discuss it.” It is a requirement for promotion.

Why do we do that? It takes away some of the subjectivity for technical promotions, but we know that there is value for the company. When somebody picks up an SPE journal and sees a paper on simulation from Schlumberger, we may gain a simu-lation customer.

But you cannot insist that employees write papers without giving them the time to do that and the time to go to conferenc-es and learn from others presenting papers. It has to be part of the culture of the company.

Lastly, it benefits SPE’s mission of communicating techni-cal information; papers are the lifeblood of SPE. Without them, what are we? I certainly think it is the place for SPE to start a campaign re-emphasizing the fundamentals of writing papers and the importance of writing papers, from section to section and chapter to chapter, giving advice on how to do it. Yes, that’s another thing I’ll push. JPT


STRATEGIC PLAN


Editor’s note: The SPE Board of Directors approved the SPE Strategic Plan 2013–17 in March 2013. The SPE Strategic Planning Steering Committee consisted of Ganesh Thakur, SPE 2012 President and Steering Committee Chair; Mark Rubin, SPE Executive Director; Egbert Imomoh, SPE 2013 President; Ken Arnold, SPE 2012 Vice President Finance; Janeen Judah, SPE 2013 Vice President Finance; Alain Labastie, SPE 2011 President; and Jeff Spath, SPE 2014 President-Elect. Consultant and facilitator was Susan S. Meier, Principal, Meier and Associates.

Since its inception 55 years ago, SPE has remained constant in its mission to col-lect, disseminate, and exchange tech-nical knowledge and to provide oppor-tunities for professionals to enhance their technical and professional com-petence. SPE is increasingly aware of the impact a changing environment and global influences may have on its abil-ity to be effective in serving an increas-ingly diverse membership in a highly complex industry.

By all objective measures, SPE is a highly successful organization. SPE has seen dramatic growth in member-ship globally (Fig. 1) and in the num-ber of meetings offered (Fig. 2) to serve these members. At the same time, SPE has added new programs, expand-ed the reach of its programs and ser-vices, opened new offices to serve its global membership, and worked with

other organizations to create great-er value for members and the industry as a whole.

One SPEThroughout this period of strong growth, SPE has strived to operate in a manner consistent with a set of One SPE Guiding Principles adopted by the Board in September 2001:

◗◗ The Society of Petroleum Engineers is a diverse community of professionals that provides valuable knowledge and services to those professionals and to the industry in varied forms.

◗◗ The concept of One SPE reflects the goal that each function and activity of the Society should serve the broader membership while

SPE Strategic Plan Identifies Four Priorities

Fig. 1—Growth in SPE membership. Fig. 2—Number of meetings.

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STRATEGIC PLAN


addressing local needs, supporting technical and professional excellence, and making wise use of Society resources.

◗◗ The voluntary donation of time and talent by SPE members is our most vital asset and the creative energy of volunteers must be encouraged and supported by the Society.

Threats to SPE’s SuccessWhile SPE has achieved great success, several factors could affect its ability to sustain this success.

◗◗ Oil and gas price volatility. The price of oil and gas is a key external factor that can affect SPE activities, including meeting attendance, membership, and participation in other programs. While SPE cannot influence the price of oil and gas, it can develop contingency plans for how to adapt the business to a sharp and sustained decline in prices.

◗◗ Technical quality within SPE programs. Rapid growth in SPE programs has led to concern that the quality of programming could be affected. To sustain its success, SPE must ensure that technical quality is not compromised.

◗◗ Volunteerism. The changing demographics of SPE’s membership mean that more members come from areas that lack a tradition of volunteerism. Coupled with the pending retirement of many of SPE’s longtime active volunteers, SPE could face a significant challenge to following its traditional volunteer-driven path to programming.

At the same time that SPE pursues its strategic priorities, it must consider ways to manage or mitigate the potential impact of these threats to its business.

Developing a New Strategic PlanSPE leaders determined that it was time to reassess and either confirm or reca-librate its direction and core strategies to ensure its continued long-term suc-cess. In June 2012, SPE launched a stra-tegic planning process to look at the direction the industry is moving and to develop a new SPE Strategic Frame-work for the next 5 years. The initiative, led by Ganesh Thakur, SPE President; Mark Rubin, SPE Executive Director; and a Steering Committee comprising five board members, was organized in three phases:

◗◗ Phase I was to gather data and best thinking from multiple sources both within and outside the organization: leaders in the field, SPE members, SPE Board Members, and SPE staff. The data collection findings included 85 responses to a strategic planning survey, 13 one-on-one interviews with industry leaders, and a July senior staff leadership team workshop.

◗◗ Phase II of the process was a 1-day facilitated Strategic Planning Workshop for the SPE Board of Directors and the SPE staff who work with Board Committees.

◗◗ Phase III engaged the Steering Committee and SPE staff leadership team in combining and advancing the workshop discussions and creating a high-level 5-year Strategic Plan to guide SPE decision making and priority setting through 2017.

This process led to the identifica-tion of four key strategic priorities. SPE’s Board Committees and work groups will examine these priorities and devel-op specific initiatives to address them over the next 5 years. SPE should also evaluate whether it has the appropriate infrastructure (governance and staff) to ensure its long-term success.

Strategic PrioritiesSPE identified four key areas of focus to advance the Society over the next 5 years.

1. Capability development (to support industry in dealing with the “big crew change”)

Areas of challenge or opportunity associ-ated with this strategic priority that SPE may choose to address include:

◗◗ Accelerate competency development. Those coming into the industry will have to gain skills and be prepared to take on responsibility quickly as retirements accelerate. New professionals will need mentoring, training and other resources to fill the gaps in their knowledge. While technical skills are crucial, the full skill set required for success must be addressed through a combination of technology and soft skills training to accelerate competency.

◗◗ Support faculty development and retention. Universities struggle to recruit, develop, and retain faculty because of the numerous opportunities available in the private sector. This has created a zero sum game in which universities recruit faculty from each other without increasing the total pool of educators. Universities face a “crew change” of their own, which will exacerbate the staffing challenge.

◗◗ Fill faculty gap with experienced professionals. The number of future industry professionals is limited by the availability of faculty. There may be several ways to address this, including the creation of opportunities for qualified industry professionals to teach in universities. This could be something that companies would support for their technical leaders and might also be attractive to experienced professionals transitioning to

StrategicPlan.indd 44 8/19/13 10:03 AM


retirement. Universities would need ways to identify those who will make good educators.

◗◗ Facilitate life-cycle learning strategies (for any career stage). For professional development and advancement, individuals at all stages of their career have a need to master new areas of expertise, equip themselves for new responsibilities, and keep their technical knowledge current.

◗◗ Assess competency. Both companies and individuals need measures for competency—ways to demonstrate that certain skills have been acquired and can be put to use. Availability of competency assessment tools could encourage members to train themselves in new areas and be used to show prospective employers that they are ready for a particular assignment. Within companies, assessment methods are necessary to measure whether competency development has been successfully accelerated. An additional benefit could be to communicate to the public that engineers have demonstrated certain levels of professional competence.

2. Knowledge transfer

This priority offers many opportunities, along with some challenges that SPE may be able to address:

◗◗ Maintain and enhance technical quality within SPE programs. With the rapid growth in SPE meetings and other programs, questions have been raised whether that growth may have negatively affected the timing of knowledge delivery to members, quality of papers, and other program elements. Ensuring that the technical content offered through its programs remains of the highest quality is crucial to SPE’s success.

◗◗ Address volunteerism issues. SPE relies heavily on member volunteers for its programs and especially to provide technical expertise. Volunteerism is not common in many areas outside the United States and western Europe. As membership from these areas grows, SPE will be challenged to apply its traditional model successfully. The Society must explore ways to make volunteering for its programs more efficient, effective, and attractive to its members.

◗◗ Make knowledge available on demand and in user-friendly ways. Technology has enhanced member expectations for the delivery of technical knowledge when, where, and in the format needed. Offerings must be easy to use and provide the features that members expect.

◗◗ Address language issues. While English remains the language of the oil and gas industry, SPE has a growing membership with limited English skills. Determining to what extent that translation is appropriate or needed and how to fill any gaps will be an important aspect of serving these members and the growing membership in certain regions.

◗◗ Take full advantage of communications technologies. New technologies open the possibility for new types of events, new methods of content delivery, and new ways for members to network and communicate. For continued success, SPE must explore the potential of these technologies and deploy those that enhance the value of what is offered or support volunteer participation in SPE activities.

◗◗ Enable identification and closure of technology gaps. As R&D has become more dispersed across the industry, it can be challenging

to know whether technical gaps are being addressed. Better means for identifying the technical capabilities required for the development of world oil and gas resources are needed. SPE may be in a unique position to facilitate discussions and exchange of information regarding gaps in existing technologies and whether other industries may have applicable technologies that could be deployed.

◗◗ Complete and promote use of PetroWiki. PetroWiki has the potential to become an invaluable technical resource for industry through member contributions. It will serve as a vehicle for both capturing and sharing the technical knowledge of SPE’s members. Making PetroWiki content available publicly increases transparency and supports SPE’s image as an independent technical resource.

◗◗ Serve as a curator of content. The volume of information available continues to increase and can be overwhelming. Sorting through vast quantities of content and identifying the material of greatest value or relevance for members will enhance SPE value.

◗◗ Determine future of peer-reviewed journals. The value of peer-reviewed content is clear and peer-reviewed journals are crucial to the academic community. Yet, like many publishers, SPE has seen declining subscriptions to its journals. Submissions for peer review have declined as the industry becomes busier and oil companies have reduced the amount of research they perform. Reconciling these trends is important to supporting industry academics who educate future engineers.

◗◗ Facilitate mentoring. The retirement of experienced professionals disrupts the informal mentoring that occurs


STRATEGIC PLAN


on the job with new engineers. The knowledge transferred in these interactions covers both technical and corporate skills. As retirements increase, filling the mentoring gap may provide opportunities for SPE to address this need.

3. Promoting professionalism and social responsibility

Several opportunities that SPE should consider in this area are:

◗◗ Emphasize SPE’s professional code of conduct. There is a growing trend for government organizations to require that professional engineers be part of an organization that emphasizes accountability for professionalism (as an alternative to the government setting up its own mechanisms). Although SPE has long had a Guide for Professional Conduct, it has not emphasized accountability and should evaluate to what extent that is an appropriate path forward for SPE. Developing a common global understanding of professional behavior is another area to be addressed.

◗◗ Incorporate ethics and ethics education in SPE programming. The growing interest in ethics and need for ethics education should be addressed by SPE.

◗◗ Provide certification—both general and discipline specific. As the pool of available talent grows in nontraditional areas, companies need ways, such as certification, to ensure that the technical training received by those individuals is sufficient to meet their needs. Even for professionals with industry experience, knowledge that the individual meets certain competency standards in a discipline has value to both employers and prospective employees. Government agencies

are also showing interest in knowing that certain industry positions are filled by individuals with demonstrated expertise, which could necessitate certifications in specific areas of knowledge.

◗◗ Promote safety and environmental protection as high priorities with our membership. Over the past 2 decades, industry has become far more cognizant of the far-reaching environmental and social consequences of its activities. While many companies have very strong safety and environmental programs, several recent incidents have reinforced public and government skepticism of the industry’s focus on these issues. SPE should emphasize safety, the environment, and sustainability to its members as a complement to current corporate efforts. Ensuring that environmental and social responsibilities are part of SPE programming may provide opportunities to improve awareness and perception.

◗◗ Maintain integrity and independence of SPE. As an individual membership society that emphasizes technical knowledge, SPE is viewed as credible and independent of corporate influence. As SPE evaluates future opportunities, it is crucial to retain its integrity and independence. Sharing this emphasis with local sections to inform their activities is also important.

4. Public education about petroleum engineering profession and industry issues

Communicating industry activities pub-licly yields several challenges and oppor-tunities that SPE may choose to address:

◗◗ Attract young people to the industry. Public perception of the

oil and gas industry is poor in the US and western Europe, thereby increasing the challenge to attract young people to industry careers. Enhancing energy and science, technology, engineering, and math (STEM) education in schools helps to counter those perceptions, and there may be other ways that SPE can help to make the industry an attractive career choice.

◗◗ Develop public awareness programs based on technology. The technology used by the oil and gas industry is complex and not easily understood by the general public. This makes public perception subject to inaccurate interpretations of technical information. Making technical information accessible and enhancing awareness based on that information is a possible role for SPE.

◗◗ Serve as a technical authority/trusted source of unbiased information. SPE may be able to leverage its reputation for integrity and technical excellence to provide white papers, case studies, and other factual, technical information to governmental organizations and the public. These materials can help both industry and the public by explaining technologies, technical issues, best practices, and challenges in meeting the world’s energy needs.

◗◗ Leverage membership to provide expertise on technical issues. As SPE works to leverage its technical reputation to expand public information, it is important to position the Society as an organization of technical experts. When expertise is required to assist a government organization, or speak publicly, SPE should have a process to identify members with appropriate expertise to serve in that role. JPT


YOUNG TECHNOLOGY SHOWCASE


Today’s field developments are increas-ingly characterized by complex wells in demanding and costly operating envi-ronments. Not only are individual wells challenging, but most are part of a com-plex reservoir network that must be man-aged over an extended period.

The high cost and risk of acquir-ing reservoir surveillance information using conventional technology, such as production logging tools, is forcing operators to manage these fields with-out knowledge of the inflow distribution across the reservoir interval. In addi-tion, permanent reservoir surveillance solutions based on optical or electronic sensors require major modifications of the completion design and installation procedure. Consequently, a significant amount of complexity and risk are added to the project, making the use of such technologies prohibitive.

Intelligent chemically based inflow tracer systems are an emerging technol-ogy that consist of engineered polymers

and chemical compounds combined into a product that resembles strips of plas-tic. The tracer system is designed to react to either oil or water. For exam-ple, when a water-sensitive tracer sys-tem is contacted by water, the tracer sys-tem releases its unique chemical identi-fication (inflow tracer) at a prescribed release rate, irrespective of the flowing conditions. The water-sensitive tracer system is dormant when contacted by oil, gas, or air. The oil-sensitive tracer system behaves similarly as the tracer is released only when it comes in contact with oil.

Strips of the tracer system are read-ily integrated into almost any completion configuration including conventional sand screens, inflow control device (ICD) sand screens, multistage fracturing sys-tems, pup joints, and intelligent comple-tions. Additionally, the tracer system can be cemented behind casing and perforat-ed through, providing contact between reservoir fluids and the intelligent tracer

strips. In summary, the intelligent trac-er strips can be deployed in almost any well type without affecting the installa-tion process.

Samples of produced fluid are ana-lyzed for the concentration of each intel-ligent tracer. Tracer concentration data, combined with model-based interpre-tation techniques, enables the opera-tor to understand where oil is entering the well, where water influx is occur-ring, and relative oil contributions of monitored zones.

The technology has been deployed onshore and offshore in locations such as Alaska, the North Sea, Australia, west Africa, and the US Gulf of Mexico. Oper-ators have benefited from this technol-ogy by gaining insight into inflow distri-bution without having to run a produc-tion logging tool (PLT) log or needing to perform complex and risky comple-tion design modifications to accommo-date electronic or optical sensors across the reservoir.

Intelligent Inflow Tracers ObtainInformation With Less Risk, CostBrock Williams and Vinicius Carvalho, Resman

Inserting tracer systems into a sand screen. Intelligent tracer carrier mandrel

YoungTechSept.indd 50 8/14/13 7:34 AM


Key benefits of the technology in-clude the following:

◗◗ Minimum implementation risk: It does not require cables, connections (wet mates), or well intervention. Additionally, there is minimum impact to existing completion design.

◗◗ Cost efficiency: There is no additional rig time or personnel required on site to run the completion. This is because the system integration is done ahead of time during manufacturing or where the inventory is located.

◗◗ Health, safety, and environmental (HSE) compatibility: The technology does not use radiation and is HSE-compatible for water discharge in extremely low concentrations (down to parts per trillion).

Examples of insight that intelli-gent tracers have provided include the following:

◗◗ Multizone fracture analysis that showed some zones were not producing and behind-pipe flow was occurring in other zones

◗◗ Location of water influx as it changes over time

◗◗ Evidence of flow contribution from the toe of a long horizontal well

◗◗ Poor contribution from one lateral of a multilateral well

◗◗ No flow coming from intervals thought to be productive

◗◗ Flow detected from downhole sliding sleeves thought to be closed

◗◗ No flow from sliding sleeves thought to be open

◗◗ Assurance that remotely activated sleeves actuate as expected

Location of Water Influx It is common for a well to start producing water at some point during its life. Know-ing the location in the well where the water is coming from is valuable infor-

mation for improved management of the reservoir.

Intelligent inflow tracers can prove useful in this application. They are designed to release their unique chemi-cal compound only when contacted by water. This feature allows the life of the water tracer system to be significantly extended as none of the tracer is being released during the time the tracers are in contact with oil.

Fig. 1 illustrates an example of using intelligent inflow tracers for water break-through detection. In the figure, each vertical line represents the location of a joint of screen that contains intelligent tracer. Each color represents a unique chemical compound contained in the tracer system.

If water is produced from one of these intervals, it will contact the tracer system in the screen, causing the chemi-cal compound to be released.

Samples of the produced water are analyzed and the concentration of the

tracers provides insight into where water production has occurred along the reser-voir interval.

Fig. 2 shows a plot of the water trac-er concentration data for samples taken over 3 months. The colored lines cor-respond to the colors of the intelligent tracers in Fig. 1. The grey dashed line is the water cut during the time period measured from a multiphase flow meter and is plotted against the right axis. Point A in Fig. 2 identifies the point in time when a sharp rise in the concen-tration of the tracers occurred, desig-nated by the blue color. A correspond-ing change in the slope of the water cut is also observed. The conclusion is that the rise in water cut at this point in time occurred in the blue zone.

Point B identifies a sharp rise in the concentration of the green tracer. A cor-responding rise in the water cut curve is also detected.

The location of water breakthrough information is used to improve the

Fig. 1—Tracer locations.

Fig. 2—Plot of water tracer concentration vs. time.

YoungTechSept.indd 51 8/12/13 1:11 PM



understanding of the overall flow dynam-ics in the reservoir and also to verify that the multiphase meter is calibrated to pro-vide accurate information. This informa-tion can be used to improve recovery by modifying future well-location, comple-tion-technique, or waterflood operation-al strategies. Wells can be designed such that intervention operations can shut off water-producing zones remotely or by intervention operations.

Inflow Distribution Assessment Using the Flush-Out ModelFig. 3 illustrates a technique in which the tracer system strips are integrat-ed into an ICD-style sand screen dur-ing the screen manufacturing process. The screens are installed in the well as normal practice and positioned across the reservoir section. When the tracer system strips come in contact with oil, tracer molecules are released from the tracer system.

During a shut-in period, the trac-er system continues to release the trac-er even when there is no flow. The oil immediately surrounding the tracer sys-tem strips acquires a high concentration of the tracer chemical. When the well is turned on, the oil with the high con-centration of tracer is flushed out of the screen and into the main flow stream of the well.

An analysis of samples taken at reg-ular intervals at the surface will detect the rise and fall of tracer concentration as the oil that contains the high tracer concentration is produced to the sur-face. The shape of this plot is indicative of the productivity of the interval being monitored. The response is best when isolation packers are used to ensure the response is from the zone of interest. The rate of rise and fall in concentration is compared among all the monitoring locations. The more prolific zones will flush out the ICD faster and will there-

fore, exhibit a sharper rise and fall in concentration when compared with the less prolific zones.

The example shown in Fig. 3 illus-trates this behavior. The character of the curves indicates that Zone 1 is the most prolific contributor. Zone 2 is a minor contributor.

This behavior has recently been studied in a flow loop using full-scale completion components. This testing is being performed at a multiphase flow facility operated by the Institute for Energy Technology in Norway. The test-ing is being conducted as part of a joint industry project that includes two North Sea operators.

The results of the flow loop test-ing have verified the validity of the trac-er decline rate as a direct indicator of inflow compared with the decline rate of other zones in the well. The accuracy of a proprietary mathematical model that converts the decline rate of tracer con-

Fig. 3—Relative inflow assessment.




centration to percentage of total well flow also has been confirmed, thereby providing a quantitative inflow analysis of each zone.

The accuracy of this method is dependent on good displacement effi-ciency; therefore, the best results will be obtained when single phase fluids are present. Significant amounts of water or gas will alter the effectiveness of the flush out. The effect of multiphase fluids on the tracer decline is the focus of ongoing flow loop testing and research and develop-ment work.

It should be noted that even in situ-ations when inflow conditions are not ideal for quantitative analysis, there are

rarely any viable alternatives for acquir-ing “across-the-reservoir” surveillance information. Intelligent tracer technol-ogy will still provide qualitative insight into each zone’s performance.

With this knowledge, the opera-tor can assess potential reasons for the difference in production and feed this insight into the reservoir simulator to improve reservoir understanding.

The Tracer Shot ModelAs described earlier, the tracer system releases the tracer chemical when it comes in contact with its target fluid, oil, or water. When the well is static, the concentration of the tracer increases in

the fluid in the immediate vicinity of the tracer system. The previous example illustrated how this effect can be used to determine relative inflow distribution when the tracer system is placed in an annular area that is connected to the main flow stream.

Another technique is to deploy the tracers in the main flow stream instead of an annular area.

The oil that is on the inside of the mandrel develops an increased con-centration of the tracer during shut-in periods. When the well is turned on, this oil is displaced directly to the sur-face. By deploying several carrier man-drels containing unique tracers at var-ious locations in the well, the differ-ence in produced volume between the arrivals of these slugs of fluid (referred to as “tracer shots”) is used to deter-mine the inflow distribution. Fig. 4 illus-trates the location of tracer carriers in a multilateral well.

During a brief shut-in period the intelligent tracer shots are developed at each carrier location. The well was turned on and sampled at a frequency of 4 samples per hour during the few hours that the tracer shots were expected to arrive at the sample point.

The tracer shot arrival technique does not use the decline rate of the tracer concentration, only the produced volume when each peak of tracer concentration arrives at the sample point. To facilitate determination of when the peak concen-tration arrived at the sample point, the tracer concentration data is normalized. Fig. 4 shows the normalized concentra-tion data of each of the tracers plotted against the produced volume associated with each sample. The spacing between the concentration peaks is a function of the inflow distribution across each lat-eral. A simulator is used to work out the inflow distribution that would create this arrival pattern.

Fig. 5 illustrates the good correla-tion achieved by the simulator after sev-eral iterations were performed to match the actual arrival of each peak with the simulator’s predicted arrivals, which are

Fig. 4—Tracer carrier locations in a multilateral well.



represented by the dashed lines. The inflow distribution that creates this cor-relation is shown in the upper portion of the figure as a percentage of total flow.

This analysis indicated several inter-esting features including the observa-tion that 43% of the flow is originat-ing from the toe of the upper lateral. Knowledge of the inflow distribution of each lateral is useful in designing the placement and design of future wells to optimize recovery.

Conclusions◗◗ The management of reservoirs

is made more challenging by the difficulty in obtaining reservoir surveillance information from complex wells in high operating cost environments. In many cases, there is no “across-the-reservoir” inflow distribution surveillance information obtained for the life of the field.

◗◗ Intelligent tracer technology can be deployed in a variety of forms and methods that have a minor impact on completion design and effectively no additional risk to the overall success of the well.

◗◗ Intelligent tracers have shown the ability to provide inflow distribution information in a variety of situations that otherwise would have proved impractical to obtain. JPT

Fig. 5—Actual vs. predicted arrivals.

YoungTechSept.indd 55 8/19/13 10:05 AM


T he oil and gas industry is today drilling in environments that 50 years ago were viewed as extreme. Drilling fluids and equipment—including

pipe, bits, motors, batteries, collars, MWD/LWD tools—as well as jars, fishing tools, wireline tools, cement, and hydraulic fracturing fluids, routinely tackle bottomhole temperatures up to 180°C, pressures of 10,000 to 15,000 psi and more, depths greater than 25,000 ft, and matrix permeabilities in the range of 100 nanodarcies. The oil and gas drilling environment remains inherently extreme, with dangers attached to managing flammable liquids and volatile gases under high pressure. However, huge leaps in knowledge, experience, science, and technology have increased safety through procedures and automation, increased certainty through modeling and real-time sensing, and increased reliability through research and development leading to sophisticated testing and ruggedized materials.

But while many fields today are drilled, re-drilled, or stimulated within the industry’s conquered range, the frontiers keep expanding. However, there are other

environments—including space, geothermal, and deep Earth scientific drilling—whose frontiers have always been more extreme. Humankind’s desire to push physical limitations has led it to delve more deeply into outer space and within our planet. Drilling in these extreme environments is helping drive advances in the oil and gas industry and/or presents analogs that can be mined for insight. One such type of drilling is extraterrestrial drilling.

Designing Curiosity’s Actuator ElectronicsAccording to the technical article, “Engineering Systems for Extreme Environments,” by Guy V. Clatterbaugh, Bruce R. Trethewey Jr., Jack C. Roberts, Sharon X. Ling, and Mohammad M. Dehghani, most of whom are members of The Johns Hopkins University Applied Physics Laboratory (APL), “Extreme environments in general can typically be categorized as involving abnormally high or excessive exposure to cold, heat, pressure, vacuum, voltage, corrosive chemicals, particle and electromagnetic radiation, vibration, shock, moisture, contamination, or dust, or extreme

An artist’s concept illustrates what the Mars rover Curiosity looks like on the Red Planet. Courtesy of NASA/JPL-Caltech.

Drilling in extreme

environments: Space Drilling and the

Oil and Gas IndustryRobin Beckwith, senior staff Writer

Drilling in Space Sept.indd 56 8/13/13 2:08 PM

fluctuations in operating temperature range.” The authors point out that “These situations are made more extreme when, upon deployment, the system is no longer available for maintenance or repair.”

The article, which appeared in Johns Hopkins APL Technical Digest, Volume 29, Number 4, details the approach used in material characterization and environmental testing of the US National Aeronautics and Space Administration (NASA) Jet Propulsion Laboratory (JPL) Mars Science Laboratory Curiosity rover actuator electronics. This is the very same electronics system used to actuate Curiosity ’s robotic arm, the part of the rover responsible for completing two exploratory drilling milestones from the Martian surface this year, one on 8 February (a borehole named “John Klein”) and the other on 19 May (a borehole named “Cumberland”).

The careful, detailed approach APL used may help inform analogous characterization and testing efforts in the oil and gas industry.

Mars is indeed an extreme environment “where there is little a priori knowledge about how the system will

function.” To obviate failures occurring on the expensive Curiosity mission, the authors discuss important testing and simulation that took place to mitigate system risk, assure system performance, and improve system reliability. “For programs operating in extreme environments, identifying and being prepared to address risk at the earliest stages of concept development is imperative,” the authors state.

One of JPL’s main reliability concerns involved the chip-on-board assemblies (i.e., printed wiring boards with integrated circuits that have been removed from their plastic “packages”). Curiosity was designed with a heated compartment to protect its computer and most of the electronics from the extremes of Martian temperatures. However, the electronics that actuate the motors on the arm and wheels are located far from the heated body and must operate at temperatures that fluctuate from –127°C to +30°C, the maximum daily temperature range on Mars. They are thus more susceptible to failure than Curiosity ’s protected computer.



DRILLING IN SPACE


The article asserts that JPL sought APL’s assistance in material characterization and environmental testing. APL says, “One pitfall to be aware of when designing the system is to watch for a critical element on which the entire design may depend. If this element poses some risk, the fallback position would necessitate an entire redesign.”

For example, say the authors, “quite often in electronic packaging of spacecraft electronics, the choice of a connector will determine the arrangement of boards in a chassis, the size of the boards, and even the chassis configuration itself. If the connector proves to be unreliable and there is no equivalent fallback connector, the entire chassis and the electronic subassemblies would have to be redesigned and possibly remanufactured. Such design dependencies or ‘linchpins’ should be avoided if possible to reduce system risk.”

The Physics-of-Failure MethodAPL opted to use what is termed the physics-of-failure method, which is a science-based approach that uses modeling and simulation to design in reliability. The method, if not already in use, might prove valuable to the development of materials and electronics for use in extreme oil and gas environments. This approach, say the authors, “models the root causes of failure, such as fatigue, fracture, wear, radiation, or corrosion.” They cite computer-aided design (CAD) tools that have been developed to address various failure mechanisms.

According to the authors, the physics-of-failure approach involves the following:

◗ Identifying potential failure mechanisms (chemical, electrical, physical, mechanical, structural, or thermal process leading to failure), failure sites, and failure modes

◗ Identifying the appropriate failure models and their input parameters, including those associated with material characteristics, damage properties, manufacturing flaws and defects, and environmental and operating loads

◗ Determining the variability for each design parameter when possible

◗ Computing the effective reliability function (e.g., Weibull function) (Note that a significant amount of testing is typically required for computing such a reliability function, and in many cases a simpler “go/no-go” test may be preferred. However, many existing reliability functions for electronic systems are available in the literature.)

◗ Accepting the design, if the estimated time-dependent reliability function meets or exceeds the required value over the required time period

The authors state further, “The most common simulation techniques for physics-of-failure modeling in electronic systems include finite element calculation of temperature, stresses/strains, random shock, vibration, buckling, thermal stress, creep, fatigue, mass transport, and electromechanical reaction rates. Statistical methods using Monte Carlo simulations and Arrhenius-based models are also commonly used.”

APL’s desire to use a physics-of-failure approach to addressing the extreme environment on Mars led to a further collaboration with the University of Maryland’s Center for Advanced Life Cycle Engineering.

Before APL designed the temperature cycling testing plan, all potential failure sites were identified using the physics-of-failure methodology:

◗ Substrate fracture ◗ Substrate bond pad lifting

“Cumberland,” drilled by Curiosity on Sol 279 (19 May), will check results from “John Klein,” located about 9 ft away. Image also taken by Curiosity’s Hand Lens Imager. Courtesy of NASA/JPL-Caltech/MSSS.

At center is the hole in a rock call “John Klein,” Curiosity’s first sample drilling on Mars. Curiosity’s Mars Hand Lens Imager took the image on 6 February, the mission’s Sol 182 (Mars days are called “sols”). Courtesy of NASA/JPL-Caltech/MSSS.


DRILLING IN SPACE


◗ Wire breakage, wire thinning, and ball shear ◗ Adhesive failure at the die/substrate interface ◗ Encapsulation cracking

Temperature Cycling Testing, Life Test, and Material CharacterizationThe APL’s testing and characterization efforts also could find application in developing electronics used in extreme oil and gas environments.

The temperature cycling testing was carefully designed to properly test all the critical failure points.

Three failure modes were observed after extensively testing various materials and careful inspection, using X-ray tomography, of the effects of the testing. All failures were either wire failures or substrate pad lifting failures. Based on the testing and inspection outcome, a combination of the polyimide substrate, an 84-1 die attach adhesive, and a 4402 “glob top” was selected.

Additional “test coupons” were constructed and subjected to a life test performed for a period of more than a year, with a daily temperature cycle between -125°C and +80°C without a failure. The authors state, “Performing an environmental test without using an acceleration factor is a bit unorthodox, but the lack of sufficient existing reliability

data over this extended temperature range and the cost associated with failure made the duration of this test a prudent measure.”

APL then carried out a material characterization study to measure the coefficient of thermal expansion (CTE), Young’s modulus, and yield strength as a function of temperature for a variety of materials. Four testing methods were used:

1. The dynamic mechanical analysis technique (DMA)—The DMA testing method is particularly well suited to flexible materials such as silicone glob-top encapsulants and the flexible conductive die-attach adhesives.

2. Uniaxial tensile testing apparatus—This is used for obtaining yield strength for the rigid epoxies and encapsulants.

3. The interferometric strain/displacement gage method—This was assembled at APL for measuring millimeter- and micrometer-scale materials in cases where bulk properties were not valid.

4. A flat-plate dilatometer—This was used to measure the CTE of candidate materials as a function of temperature.

The next step was to create an optimized wire bond analytical model. APL personnel attempted to optimize the shape of a wire bond by minimizing its strain energy. “We used the principle that the lower the initial strain energy, the more likely it is that the wire board can sustain deformations without a loss in structural integrity,” the authors state. “The approach taken here was to develop an optimized wire bond shape that was the least susceptible to strains caused by deflections in the glob-top material.”

The finite element method (FEM), which facilitates the use of nonlinear, time-dependent, and temperature-dependent analysis methods, was used by APL personnel to analyze an encapsulated 2-mil gold wire bond for the Curiosity rover actuator electronics. According to the authors, “The nonlinear FEM was a one-quarter symmetric model and simulated the stresses resulting from a wire-bonded chip cooled from the cure temperature (150°C) down to –125°C. A coupled thermomechanical

These schematic drawings show a top view and a cutaway view of a section of the drill on NASA’s Curiosity rover on Mars. Courtesy of NASA/JPL-Caltech.

Top View ofCuriosity’s Drill

Section View of Curiosity’s Drill Bit

Contact Sensor/Stabilizer

Chamber 2

Chamber 1

Sample path

Exit toCHIMRA


DRILLING IN SPACE


finite element analysis with temperature-dependent material properties was used. The analysis confirmed that the glob-top encapsulant chosen for the actuator electronics would not produce an overstressed condition in the assembly, confirming the results of the cycling tests.”

APL cited good correlation between the testing and evaluation (T&E) and the modeling and simulation (M&S) results. The authors state, “It is important to emphasize the link between T&E and M&S. We stated previously that M&S results should guide testing, but the reverse is also true: Good test data should be used to refine models and simulations. This is often an iterative process requiring several M&S and T&E cycles to refine system models.”

Because the Curiosity actuator electronics program produced such good results, the authors are hopeful that long periods of expensive testing can be replaced with relatively inexpensive short-duration simulations for future Martian missions.

Curiosity’s Actuated Drilling Arm in ActionCuriosity was launched from Cape Canaveral 26 November 2011 aboard the Mars Science Laboratory spacecraft. Following the 563,000,000-km journey and after a rather torturous descent (dubbed the “7 minutes of terror”), Curiosity, divested of the spacecraft, landed safely on Aeolis Palus in Gale Crater on Mars on 6 August 2012.

On 6 February 2013, Curiosity ’s actuated arm-mounted percussive drill hammered a borehole, dubbed “John Klein,” 6.4 centimeters deep into a Martian outcrop. “This is the first time any robot, fixed or mobile, has drilled into a rock to collect a sample on Mars,” Louise Jandura, sample system chief engineer for Curiosity at NASA’s JPL in Pasadena, California, told reporters.

However, extraterrestrial drilling has also taken place on the moon. Those cores are the only ones returned to Earth, collected by US Apollo mission astronauts (late 1960s and early 1970s) and Soviet Luna program robotic spacecraft (early to mid-1970s) on the lunar surface. The moon, of course, is much closer to Earth than the planets, at a distance of (only) 384,400 km. Mars is a little less than 1,500 times farther away. But, unlike the moon, Mars may have been capable of supporting life.

By the time Curiosity conducted its second drilling operation, 19 May, named “Cumberland,” the results of the first drilling revealed that ancient Mars was likely capable of supporting microbial life—groundbreaking if it is corroborated. According to NASA officials, “The science team expects to use analysis of material from Cumberland to check findings from John Klein.”

Extraterrestrial Drilling ConstraintsMissions like the Curiosity stretch the bounds of drilling in an extreme environment, yet at the same time present many constraints that limit their operation. A number of these are noted in SPE Paper 111126, “Drill Automation for the Space Environment: Lessons Learned,” by K. Zacny and G. Paulsen, Honeybee Robotics, and G. Cooper, University of California at Berkeley. In addition to simply surviving the journey from Earth’s surface to the surface of an extraterrestrial destination, the following parameters also must be observed in order to accomplish drilling in outer space:

Electric Power—Curiosity has a radioisotope thermoelectric generator. Heat given off by the decay of an isotope, in this case Curiosity ’s 4.8-kg of plutonium-238 dioxide, is converted into electricity by thermocouples. The power source generates 2.5 kWh each day. Waste heat is used via pipes to warm systems, freeing electrical power to operate

This full-resolution image from NASA’s Curiosity shows the turret of tools at the end of the rover’s extended robotic arm on 20 August 2012. Courtesy of NASA/JPL-Caltech.

Prototype Mars2020 rotary percussive core drill, called RoPeC, designed to autonomously drill, shear, and capture a rock sample. See http://www.youtube.com/watch?v=_ -hOO4-zDtE. Courtesy of Honeybee Robotics.

Drilling in Space Sept.indd 62 8/15/13 10:39 AM


the vehicle and its instruments. Two rechargeable lithium-ion batteries are charged from the generator, which enables the power subsystem to meet Curiosity ’s peak power demands when demand exceeds the generator’s steady output level. Each battery’s capacity is about 42 amp-hours. The rover’s average traveling speed is about 30 meters/hr.

In oil and gas drilling on Earth, a typical rig generator set has a nameplate rating of about 1,100 kW, with larger (around 3,500 kW) and smaller (around 550 kW) units available.

Mass—The maximum weight-on-bit (WOB) that can be applied to the drill is limited by the mass of the rover multiplied by the acceleration due to gravity. The case given in the paper is for an 850-kg rover (Curiosity is actually 899 kg), where the maximum WOB may not exceed 850 kg * 3.68 m/s2=3,100 Newton (equivalent to 300 kg on Earth). This assumes the drill is placed along the rover’s center of gravity. In Curiosity ’s case, the drill is deployed from the robotic arm, making allowable WOB much lower.

The mass is constrained by several factors, including cost of the launch, the size of the launch vehicle, and landing technologies for extraterrestrial bodes (landing on the moon is easier than on Mars, because of the lower lunar gravity).

WOB during drilling into the Earth can reach 30,000 to 50,000 lbf. On Earth, mass of the drilling rig is constrained more by its purpose than anything else, with widely different sizes and types of rigs used in a range of operations, including oil and gas well drilling, mining, water well drilling, making subsurface installations, mineral-deposit sampling, or testing rock, soil, or groundwater physical properties.

Temperature, Thermal Fluctuations, Atmosphere, and Pressure—These parameters place physical constraints on the design of all materials and mechanisms, whether used in oil and gas drilling anywhere within the Earth or in extraterrestrial drilling.

Mars: The maximum daily temperature range on Mars fluctuates from –127°C to +30°. Mars’ atmospheric pressure averages about 0.087 psi, about 0.6% of Earth’s mean sea level pressure of 14.69 psi (equivalent to 120,000 ft above Earth’s surface). Mars’ atmospheric mass is about 25 teratonnes, compared to Earth’s 5,148 teratonnes, and it consists of carbon dioxide (95%), nitrogen (3%), argon (1.6%), and traces of other gases.

Earth’s Moon: There is no significant atmosphere on the moon, so it cannot trap heat or insulate the surface. Daytime on one side of the moon lasts about 13½ Earth days, followed by 13½ nights of darkness. When sunlight hits the moon’s surface, the temperature can reach 123°C. The moon’s dark side can have temperatures dipping to –153°C. The Lunar Reconnaissance Orbiter, a NASA robotic spacecraft launched mid-2009 and currently orbiting the

moon, measured temperatures of –238°C in craters on the moon’s south pole and –247°C in a crater on its north pole.

Venus: The surface temperature of Venus is about 480°C and its atmospheric pressure is about 900 Newtons per square centimeter (1,300 lb/in.2). Its atmosphere consists of about 95% carbon dioxide, with the remainder mostly nitrogen. A thick layer of clouds is thought to be largely composed of sulfuric acid droplets. None of the several Russian spacecraft of the Venera series lasted more than an hour on the planet’s surface. Earlier Venera probes parachuted into the Venus atmosphere and were crushed by it before reaching the surface. Although the European Space Agency’s Venus Express spacecraft, launched in November 2005 and arriving within Venus orbit in April 2006, has supplied images and data from its orbit, no mission since Venera has attempted to land on the planet’s surface.

Venus Drill—Temperature and Pressure: A Venus drill is discussed in chapter 6, “Extraterrestrial Drilling and Excavation,” in the book, Drilling in Extreme Environments, edited by Yoseph Bar-Cohen and Kris Zacny (Wiley-VCH, 2009). “The benefit of high-temperature motors is that they can drive a sampling drill or a grinder, robotic arm, or a deployment stage on the surface of Venus and thus allow for sample acquisition, transfer, and analysis.”

The authors note that “high temperature is a much more problematic issue to deal with than high pressure. [A] high-temperature application either requires components to withstand this temperature or necessitates some kind of an active (or passive, depending on the time of exposure) cooling system. [An] active cooling system is very expensive and many proposed sample return missions from, for example, asteroids, which had to keep samples cool, could not fit within the mission cost cap. On the other hand, a solution to [the] high-pressure problem can be solved by a pressure vessel, which is a passive system (does not require any power to work).”

Fluids—Temperature and Pressure: According to SPE Paper 111126, “In terrestrial oil well drilling, cuttings removal is often done by circulating a fluid such as water, a mud slurry, or air. In most extraterrestrial setting (moon, Mars, and asteroids), the use of a fluid is not the first choice because of low pressure and/or low temperature conditions. At these conditions, a fluid either freezes or sublimes directly to vapor. Note also that even if a low freezing point fluid were available, the launch cost in excess of USD 20,000/kg would make sending drilling fluid prohibitively expensive. For this reason, most extraterrestrial drills use an auger with helical fluting to convey cuttings to the surface. This makes the drilling process more inefficient.”

Communications Delay—“Of all the constraints, the delay in communication is probably the single most important factor



that determines the level of autonomy” in drilling on planets like Mars, states SPE Paper 111126.

Curiosity is equipped with an X band transmitter and receiver that can communicate directly with Earth (at speeds up to 32 KB/sec) and a UHF Electra-Lite software-defined radio for communicating with Mars orbiters. The orbiters have more power and larger antennas, allowing for faster transmission, and thus are relied on as Curiosity ’s main means of communicating. The Mars Reconnaissance Orbiter and Odyssey orbiter can communicate with Curiosity for about 8 minutes/day, with data transfer rates that can reach 2 MB/sec and 256 KB/sec, respectively. An average of 14 mins, 6 secs is required for signals to travel one way between Mars and Earth. Information from Earth to Curiosity has to follow the same path in reverse, with the same time delay and window of opportunity constraints.

This constraint alone dictates the need for fully autonomous robotic operation throughout most of an extraterrestrial drilling operation beyond the moon. This is quite different from the concept of automated drilling on Earth. As chapter 6 in Drilling in Extreme Environments states, “In the commercial realm, ‘automation’ and ‘remote control’ mean the capability to watch values and open and close valves with a mouse click in a control room, as opposed to sending out a human with a wrench—eliminating direct hand contact other than joysticks and touchscreens. In space, these definitions imply minimal or no direct

human involvement, even with regard to monitoring and decision-making.”

There was no real-time monitoring of Curiosity ’s drilling operations but computer command sequences were altered based on the drilling campaign at John Klein. On 5 June, the JPL reported that, “For the drill campaign at Cumberland, steps that each took a day or more at John Klein could be combined into a single day’s sequence of commands. ‘We used the experience and lessons from our first drilling campaign, as well as new cached sample capabilities, to do the second drill campaign far more efficiently,’ said sampling activity lead Joe Melko of JPL. ‘In addition, we increased use of the rover’s autonomous self-protection. This allowed more activities to be strung together before the ground team had to check in on the rover.’”

Lecture Series and Workshop Spark DialogDr. Alfred Eustes, a professor within the Petroleum Engineering Department at the Colorado School of Mines, was selected as an SPE Distinguished Lecturer for the 2013–14 program. His lecture topic is “Extraterrestrial Drilling: How on Earth Can Martian Drilling Help Us?” Eustes is convinced that “What we learn from building and deploying extraterrestrial drilling technology will help us understand how to drill better here on Earth.”

“For example,” he continued, “think of the development of autonomous drill systems for Martian deployment and how applicable those techniques could be here. How about the development of sensor technology for detecting life, assumed to be carbon based just as hydrocarbons are here on Earth? Could those be used here to find oil? And what of material development and machine design for those extreme environments? The X-15 research aircraft was an extreme machine for an extreme environment. And it paved the way for the routine jetliners we use today.”

In further pursuit of dialog between the oil and gas and space communities, a workshop on Planetary Drilling and Sample Acquisition was held 6–8 May at the NASA Goddard Space Flight Center in Greenbelt, Maryland. Several members of the oil and gas-related community participated, from companies such as Halliburton, Baker Hughes, Atlas Copco, and National Oilwell Varco, as well as from universities, NASA, and other companies such as Honeybee, QMI, and ATK (Alliant Techsystems).

Workshop co-organizer, Dr. Michael New, astrobiology discipline scientist at the Planetary Science Division, NASA, said, “The drill used on Curiosity is the best we have. But we want to go deeper. Because, for example, the Mars surface is bathed in ultraviolet radiation, everything gets chemically modified.”

He explained that the Curiosity arm is equipped with a brush that sweeps away the superficial layer of Martian red dust. “A meter or 2 will get you below most of the radiation damage,” he said. “If you want to go deeper—10s or 100s of

The Autogopher is a wireline drill, powered by a rotary-ultrasonic system, that enables reaching great depths with low system mass. See http://www.youtube.com/watch?v=CSjfKhF5Vys. Courtesy of Honeybee Robotics.


DRILLING IN SPACE


meters—this is in the realm of a multisegmented drillstring, with borehole stabilization (casing) required. This is really not possible in space at this time.”

New said he has been hampered as the manager of an instrument development program. He receives many proposals for sample acquisition devices such as drills and corers, but wanted focused, strategic guidance on which applications—and therefore technologies—are highest priority. Participants in the workshop helped develop scenarios of the timeframe and feasibility of drilling on extraterrestrial bodies such as comets, Earth’s moon, Venus, Enceladus, and Europa.

As an example, the European Space Agency’s Rosetta is the first mission (currently in “hibernation” until January 2014 on its way to rendezvous with the comet 67P/Churyumov-Gerasimenko) designed to orbit and land on a comet. According to New, it has a small drill on it. “The problem,” he explained, “is that a comet has almost no gravity, so there’s the necessity to bolt down a drill. Then there’s the problem of no weight-on-bit.”

New cited the tension between the constraints of drilling on an extraterrestrial body and the drive to push the frontiers of knowledge. In a short paper he coauthored with Dr. Brian Glass from NASA’s Ames Research Center, “Drill and Sample Acquisition Testing Using Planetary Analogs,” the results of the workshop were discussed: “Future missions requiring subsurface samples will require lightweight, low-mass planetary drilling and sample handling. As discussed in the workshop, unlike terrestrial drills, these future exploration drills will likely work dry (without drilling muds or lubricants), blind (no prior local or regional seismic or other surveys), and weak (very low downward force or weight-on-bit, especially on small bodies, and perhaps 100W of power available).”

The paper talks about the merits of using drilling analog sites (such as Arctic and Antarctic permafrost, desert, and basaltic sites) here on Earth:

◗ They provide a relevant environment for testing technical maturity, and for pushing prototypes and beta versions harder, more unpredictably, and with higher overall fidelity than in laboratory bench tests.

◗ They tend to flush out buried assumptions about durability, connectors, vibrations, and component failure rates at far less expense than on-orbit tests.

◗ They are valuable for testing and developing new operations concepts. For example, given their natural

strata and outcrops, analog sites give a more widely varied set of inputs for drill automation training than laboratory bench tests.

The Future: Mars 2020 and BeyondOn 1 July, a 154-page report was issued that had been prepared by the Mars 2020 Science Definition Team (SDT), appointed by NASA in January to outline scientific objectives for the mission. The mission will send another rover to Mars, which should look for signs of past life, collect samples for possible future return to Earth, and demonstrate technology for advancing toward human missions to the Red Planet.

“The Mars 2020 mission concept does not presume that life ever existed on Mars,” said Jack Mustard, chairman of the Science Definition Team and a professor of the geological sciences at Brown University in Providence, Rhode Island. “However, given the recent Curiosity findings, past Martian life seems possible, and we should begin the difficult endeavor of seeking the signs of life. No matter what we learn, we would make significant progress in understanding the circumstances of early life existing on Earth and the possibilities of extraterrestrial life.”

Drilling again will be a challenge. A drilling device will be crucial for the sampling system. The report states, “[T]he 2020 mission must have the capability to acquire a core from rock/outcrop. The ability to acquire a regolith [extraterrestrial unconsolidated solid material covering a planet’s bedrock] sample would be highly desirable.”

SDT’s Finding 6-1 defines the Mars 2020 mission drilling depth parameter: “The minimum threshold depth for coring into rock is 50 mm. The baseline depth for sampling into rock is >50 mm. Sampling strategies (e.g., fresh ‘bedrock’ exposed by impact) may provide opportunity to sample ‘deeper’ than 50 mm where organic material may be preserved from ionizing radiation.”

The importance of drilling and coring to this mission cannot be overstated—and the oil and gas industry has the opportunity to provide insight and analogs into drill development as well as coring operation design. Samples collected and analyzed by the rover will be essential in helping inform future human exploration missions to Mars. As laid out in a speech delivered 15 April 2010, US President Obama provided a blueprint that includes a manned trip to Mars orbit and back in the 2030s. “A landing on Mars will follow,” he said. “And I expect to be around to see it.” JPT



To commercialize some of the world’s most challenging deepwater fields, offshore engineering companies are

developing a new class of drilling and production platform known as the dry tree semisubmersible (DTS). The challenge involves taking existing technologies and lessons learned from previous floater designs to create an alternative platform for waters too deep to cost-justify the use of tension-leg platforms (TLPs) and fields too large for spar platforms.

Dry trees, also known as Christmas trees, are wellhead devices installed during the completion stage of a well’s life and give the operator control over production. Used on onshore wells, dry trees have been used extensively on shallow water fixed platforms, TLPs, and spars, but never on a deepwa-ter semisubmersible because that platform’s motions are too extreme to support a dry tree system.

As the DTS concept awaits introduction into the deepwa-ter market, multiple designs are under evaluation by major off-shore oil companies and the Norwegian classification society Det Norske Veritas (DNV).

The chief advantages of using a DTS are that opera-tors can drill, complete, and carry out intervention opera-tions on multiple wells from the same platform in depths below 6,000 ft. This saves the operator significant resourc-es that otherwise would be spent over the life of the field on contracting mobile offshore drilling units or purpose-built, well-intervention semisubmersibles.

Going Deeper With a DTSA TLP typically uses four columns to support a large topside facility and is secured to the seafloor with mooring lines that allow the floating platform to move from side to side, but not up and down. Operating at a water depth of 4,674 ft, ConocoPhil-lips’ Magnolia TLP in the US Gulf of Mexico (GOM) is the deepest structure of its kind in the world. Next year, Chevron hopes to begin first production from its Big Foot TLP, also to be located in the GOM, at a depth of approximately 5,200 ft. Beyond 6,000 ft, TLPs become impractical because of the amount of steel need-ed for the tendons that moor the platform to the ocean bottom.

The Octabuoy dry tree semisubmersible, shown at a shipyard in Qidong, China, is the first of a new type of floating drilling and production platform under construction and is owned by ATP Oil and Gas. Photo courtesy of Moss Maritime.

Dry Tree Semisubmersibles: The Next Deepwater Option Trent Jacobs, JPT Technology Writer

Dry Tree Semis.indd 70 8/13/13 2:25 PM


A spar platform supports drilling, production, and stor-age operations and achieves stability from the deep draft of the vertical column on top of which the topside sits. Spars have vir-tually no water depth limit and are designed specifically as a dry tree unit. However, their size is limited by their cylindrical hulls, which constrain the available deck space, thereby push-ing designers to stack the decks vertically. When scaled up to increase the deck area comparable to that of a TLP and to add the payload capacity required for a deepwater drilling rig, the hull of a spar introduces tremendous challenges for transpor-tation and installation. Measuring 555 ft in length, Shell’s Per-dido spar is the deepest in the world, operating at a depth of 7,844 ft in the GOM. Because the deep draft of spars exceeds the water depth near a fabrication yard and create too much drag to wet tow vertically, they must be transported on their side, then upended on location, and have the topside installed onto the hull at sea.

Operators are increasingly seeking to avoid this type of off-shore integration because of the risk and cost involved, espe-cially for large topside decks. The safer and more cost-effective option that the DTS allows for is quayside integration of the hull and topside, where sea motions are minimal and the need for a heavy lift vessel is eliminated.

A conventional semisubmersible platform offers the opti-mum amount of deck space for safer operations and pay-load flexibility that a spar cannot, but it has too much vertical motion for a dry tree to operate safely. Several semisubmers-ibles operate in depths exceeding 6,000 ft; however, all of them use subsea trees. Unlike subsea trees that are installed at the seabed and deliver hydrocarbons to a surface platform through a flexible production riser or a metallic riser such as a steel cat-enary riser (SCR), a dry tree uses a rigid riser system known as a top tensioned riser (TTR) that is locked onto the subsea well-head at the seafloor and to the dry tree at the platform deck, thereby making it very sensitive to movement.

Another difference is that when using a DTS, the rigid ris-ers dictate that the wells be drilled directly beneath the plat-form in comparison to semisubmersibles, which use subsea trees that can span large distances between each other. On a DTS, each well has its own riser, whereas in a subsea tree sce-nario, depending on the rate of production, multiple wells can tie into a single riser.

Short Stroke vs. Long StrokeAlthough the DTS hull is designed to reduce motion caused by ocean forces, it is the motions that move the platform up and down that are of the highest concern. To compensate for exces-sive vertical motion current, DTS concepts are relying on prov-en riser tensioner technology. Riser tensioners have been used on TLPs and spars for nearly 3 decades and are connected to the uppermost segment of a TTR at the platform. Like the shocks on a car, riser tensioners absorb the vertical heave motion caused by ocean waves, allowing the riser to move up and down in a controlled manner without over or under tensioning the riser.

A key difference in some of the DTS concepts is the stroke length that the tensioners need to compensate riser motions vertically. In modified DTS hull designs with deep drafts or additional dampening devices, conventional short-stroke riser tensioners are used to compensate for the heave. In conven-tional hull designs, longer stroke riser tensioners are needed to compensate for a greater heave movement. The required maximum safe range of the tensioner stroke is largely depen-dent on field conditions and can be as short as 25 ft in severe environments. To be qualified for global field development applications, each DTS concept must be designed to survive a 1,000-year hurricane in the GOM. In some designs, the riser tensioners must have a stroke length of up to 45 ft.

A driver for the modified hull DTS with a deep draft is the preference that operators have shown for a short-stroke ten-sioner length within the range of 30 ft to 35 ft (Fig. 1). However, as the length of the columns grows to mitigate heave, so does the cost of the hull. Another construction issue that will need to be addressed is whether to dredge quayside at the shipyard to accommodate a substantially deeper draft platform or complete the hull and topside integration offshore.

Aker Solutions’ dry tree tensioner technology is based on the tensioning system shown being used on a drilling rig. The tensioner compensates for the heave, or bobbing, movements of a dry tree semisubmersible. Photo courtesy of Aker Solutions.

Dry Tree Semis.indd 71 8/12/13 7:46 AM

DRY TREE SEMISUBMERSIBLES


In addition to supporting TTRs, the DTS concept is being evaluated for its applications in subsea tiebacks of satellite wells using flexible or steel catenary risers (SCRs). Connected to sub-sea pipelines and subsea trees, SCRs are flexible metallic risers that bend in a catenary shape as they deliver oil and gas to a pro-duction platform. Over time SCRs become susceptible to fatigue as the host platform sways, thereby weakening the steel at the point closest to the seafloor known as the touchdown zone. With the improved motions of a DTS hull, SCR performance could be enhanced, thus extending its service life.

Octabuoy: The First DTS Moss Maritime says its Octabuoy (Fig. 2) is the world’s first DTS concept to be purchased by an oil company and has gained cer-tification from the American Bureau of Shipping and DNV, and validation by a number of other operators as a dry tree unit. In

2008, Moss Maritime sold the license to build the Octabuoy to ATP Oil and Gas, which has completed the construction of the hull in China but has yet to commission the unit for service. The ATP Octabuoy was designed to produce up to 175,000 B/D of oil in the North Sea using subsea trees and for the deeper waters of the GOM using dry trees.

The Octabuoy’s four conical columns are connected to the octagon-shaped pontoon for which the platform’s name is derived from. The columns, which can be used for oil storage, have a profile with a variable water line and dimensions that minimize platform motions. This grants the platform superior motion characteristics compared with a spar and the transport and installation simplicity of a semisubmersible.

“We’ve placed the columns on the outside of the pontoon ring to give us greater stability,” said Roberto Noce, general manager of Moss Maritime. “Now you’re able to integrate a deck with a footprint as large as needed, and once you put in a big-ger deck, you can spread your equipment out more efficiently and safely, because you can keep hazardous areas away from the living quarters.”

The conical shape of the columns does not present fab-ricators with any significant challenges, Noce said, proving

Fig. 2—The Octabuoy has a deeper draft than a conventional semisubmersible and can be deployed to multiple fields over its expected 50-year service life. The platform’s unique column and octagonal buoyancy pontoon minimize the effects of heave, pitch, and roll motions which allow it to support dry tree wellheads at any depth. Image courtesy of Moss Maritime.

Fig. 1—SBM Offshore’s 35-ft range riser tensioner system allows its dry tree semisubmersible to move vertically while ensuring the integrity of the dry tree system located on the tensioner. Image courtesy of SBM Offshore.




that the design adheres to convention-al construction methods and semisub-mersible technology. Moss Maritime has completed multiple field-specific testing and engineering studies on the use of the Octabuoy for Chevron, Petrobras, Shell, and Statoil.

Paired Column SemisubmersibleHouston Offshore Engineering’s paired column semisubmersible (PCS) (Fig. 3) uses four large outer columns and four smaller inner columns to achieve the stability required in using existing ten-sioner technology. The inner columns support the topside decks and the outer columns provide motion stability.

By increasing the size of the col-umns, or by changing the distance between the outer and inner columns, the PCS can accommodate varying deck payloads. Pairing the columns in this configuration cancels out surge and sway motions. The paired column concept has shown that it can reduce what are known as vortex-induced motions (VIMs) caused by the loop current in the GOM. VIMs are a major contributor to the fatigue of SCRs and eliminating this type of motion would increase their service life. In June, the PCS underwent tank testing to evalu-ate its VIM performance and the results were better than expected.

“The VIM motion is actually signifi-cantly less than the single column (semi-submersibles) which gives us a big advan-tage in regards to mooring line fatigue,” said Jun Zou, manager of naval architec-ture at Houston Offshore Engineering,

He added that his company’s design is compatible with a short-stroke ten-sioner system capable of a 28-ft range for use in the most severe GOM environ-ments. The PCS is designed to process 100,000 B/D of oil and the company has completed a study to increase the design capacity to 150,000 B/D.

Conventional Semisubmersible Solutions Another approach is to use a conven-tional deep-draft semisubmersible plat-form and incorporate long-stroke riser

The paired column semisubmersible during tank testing earlier this year. Photo courtesy of Houston Offshore Engineering.

Fig 3—Houston Offshore Engineering’s paired column semisubmersible is capable of accommodating a drilling rig with a 2-million-lbm hook load in water depths up to 8,000 ft. Image courtesy of Houston Offshore Engineering.



tensioners to compensate for the greater heave motion. Kvaerner Field Develop-ment and Aker Solutions are both devel-oping DTS concepts that feature a ring pontoon with four corner columns sup-porting the topside.

The Kvaerner DTS (Fig. 4) is based on prior in-house semisubmersible designs and uses a long-stroke tensioner with a range of 35 ft. The hull is deeper than a conventional semisubmersible but within the limits that allow for quayside integration and commissioning.

“The hull itself looks a lot like a conventional semisubmersible except the draft of the underwater portion, the col-umn, is deeper, because of the riser per-formance requirement,” said Jack Zeng, director of engineering and technology for floaters at Kvaerner.

The Aker DTS (Fig. 5) concept is based on the company’s existing semi-submersible designs that have been used to build offshore units already in ser-vice. The Aker design has been modified only slightly in regards to the configu-ration of the drilling rig and well bay to accommodate for tensioner stroke and deeper columns.

The Aker DTS will use the same riser tensioner technology used on the compa-ny’s drilling rigs, but the stroke length will increase by a few feet from the current maximum range. For use in the GOM, the Aker DTS will have a riser stroke range of 35 ft to 45 ft as dictated by storm sur-vival requirements. Aker is studying the use of smaller stroke riser tensioner in areas where stroke requirements are less extreme because of calmer seas, such as off west Africa and in southeast Asia.

“This is being looked at to use around the world so that we find fields that are really perfect for a DTS with the right depth and right field conditions,” said Rolf Eide, manager of hull and marine engineering at Aker. The Aker DTS is in the final stages of qualification with DNV and Chevron.

SBM Offshore is following the same path as Kvaerner and Aker in developing its own version of a DTS (Figs. 6 and 7) by using the design of two semisubmers-ibles operating in the GOM. Compared

Fig. 4—The Kvaerner DTS, shown in an illustration being towed to sea, uses a deck box-type structure made up of a double bottom-type lower deck and an upper deck with enough vertical separation to accommodate drilling and production modules. Image courtesy of Kvaerner.

Fig. 5—Aker Solutions’ dry tree semisubmersible design is based on its previous semisubmersible designs and uses riser tensioner technology already in use on its drilling rigs. Image courtesy of Aker Solutions.




with its two other deep draft semisubmersibles, SBM’s DTS con-cept would be more than twice the weight with 50% more draft.

“We’ve extended the draft another 50 ft in our design beyond what we did for the Independence Hub and Thunder-hawk,” Randy Jordan, vice president of floating production sys-tems at SBM Offshore, said.

Independence Hub is the deepest operating semisubmers-ible in the world at approximately 8,100 ft in water depth and it processes 1 Bcf/D of natural gas. The SBM Offshore DTS has a 150-ft draft and is designed for depths up to 8,000 ft. Based on results from a wave basin model test completed in April, Jordan said its DTS design is ready to be used for field development in west Africa, Brazil, and southeast Asia. The company will reveal the results of its recent testing at OTC Brasil in October.

Challenges Remain for Adoption The riser tensioner technology that the DTS concept relies upon has been proved on drilling rigs, but not on floating production

platforms. Because drilling rigs are required to enter dry dock for inspection every 5 years and floating production facilities are designed to operate at sea for decades without coming to port, operators are seeking a high level of certainty on the long-term integrity of the riser tensioner systems.

Other safety issues that are under review include outlin-ing the contingencies for a riser tensioner or supporting system failure and the safest way to arrange the well bays so as to pro-tect the integrity of the riser tensioner system.

Consideration must also be taken in the designs regarding how to safely conduct drilling and production operations simul-taneously in a well bay crowded with multiple riser tensioners. And because no DTS has been field proven in deep water, the concept’s cost-effectiveness has yet to be determined. JPT

Fig. 7—A computer illustration of a riser tensioner system layout in the well bay of SBM Offshore’s dry tree semisubmersible design. Image courtesy of SBM Offshore.

Fig. 6—SBM Offshore’s DTS is designed to house 12 top tensioned risers and produce 100,000 B/D of oil and 50 MMscf/D of natural gas. Image courtesy of SBM Offshore.

For Further Reading:OTC 23912 A Project Oriented and Technology Robust Dry Tree Semi Concept by Jack Zeng, Kvaerner, et al.

OTC 23919 Dry Tree Semi Technology Readiness—Perspectives of Operator and Classification Society by Jenny Yan Lu and Ming-Yao Lee, DNV/Chevron, et al.

OTC 23926 An Evaluation of Strength, Fatigue, and Operational Performance of Dry Tree Semisubmersible Riser Tensioning Equipment by Jun Zou, Houston Offshore Engineering, et al.

OTC 23958 A Robust and Flexible Dry Tree Semisubmersible Drilling and Production Platform by Roberto Noce, Moss Maritime, et al.

OTC 24148 Dry Tree Semisubmersibles for Gulf of Mexico by Steve Leverette, SBM Offshore, et al.

Dry Tree Semis.indd 76 8/13/13 2:27 PM

INCUBATOR FOR STARTUPS


A handful of entrepreneurs are out to disrupt the daily routines of workers in oil exploration and production (E&P) by applying digital technologies.

The entrepreneurs are members of a generation of digital natives who grew up expecting constant online contact and information, so their ideas are typically a version of how they expect the world to work.

RunTitle wants to cut the number of days spent in courthouses search-ing title records to find the owners of mineral rights by creating a national online database.

The Global Material Exchange (Gmex) is creating an online marketplace

for the millions of tons of steel products now bought and sold using phones, faxes, and email.

Skynet Labs plans to replace spread-sheets and manual calculations by drill-ers with applications that can be used on smartphones or tablets, and ultimate-ly with a cloud-based system offering greater computing power and the ability to collaborate.

Secure Nok is going about drilling rig security from a different angle, look-ing for signs of trouble by closely analyz-ing machine performance.

Waveseis seeks to create better seis-mic images of formations otherwise obscured by thick layers of salt.

They are among the 12 companies in the second class of startups nurtured by the Surge Accelerator—a 2-year-old Houston venture created to use tech-niques developed in the technology sec-tor to jump-start early-stage companies in energy. About half the business plans are based on software to improve oil and gas operations.

Surge was founded on the premise that the energy industry is ripe for a digi-tally driven change that has transformed business sectors such as finance and manufacturing. “They (plans of Surge companies) are all focused on collecting data, managing data, analyzing data—all in real time—and providing actions on top of that,” said Kirk Coburn, managing director of Surge, who summed it up as “true real-time intelligence.”

Initially, Surge was investing only in software for energy—including alter-native energy and electricity—but its investment committee has added hard-ware. The group includes Dynamo Micro-power, which makes a simplified tur-bine that can be powered by wellhead gas to generate power. Water has also been added because it is so critical in this realm.

If these ideas turn into profit-able enterprises, Coburn and the other Surge backers have a chance to prof-it from it. The accelerator gets a 6% stake in the companies in exchange for financial support, training, mentoring, and connections to potential investors and users during a 3-month program in Houston.

Of the 23 companies backed by Surge over the past 2 years, 21 are still in business, Coburn said. In the world of technology startups, failures are a given—success often comes only after

E&P Software: The Next GenerationStephen Rassenfoss, JPT Emerging Technology Editor

Kirk Coburn, the managing director of Surge Accelerator, speaks in front of entrepreneurs who made their pitch to investors at the event put on by the Houston business accelerator that picks and promotes ventures seeking to change the energy and water businesses.

StartupsSept.indd 78 8/12/13 7:54 AM



many tries—and an idea that does not work often inspires another. Ariel Sella, the founder of one of the Surge startups that stopped, was inspired to create an accelerator called Azimpo in Tel Aviv, Israel, to support entrepreneurs work-ing to help a range of industries operate more efficiently.

While he is not targeting the energy industry, there is a common link. Both accelerators see opportunities in the exploding number of devices connected over the Internet—many of which have sensors—known as the Internet of things.

The challenge for those picking ideas is finding ones offering the upside that comes with disrupting the status quo, but there is a limit to the pace of change. Sometimes “being early is the equivalent of being wrong,” Coburn said.

Raising MoneyDuring Surge Day in late May, members of the class made their pitch to inves-tors gathered in an auditorium in the House of Blues in downtown Houston. The production made full use of the light-ing and sound system normally used for

music shows, with short pitches playing up a problem and a solution. The lineup offered an interesting sample of the digi-tal opportunities in E&P.

RunTitle’s Chief Executive Officer Reid Calhoon pitched his business by say-ing: “We are wasting our time driving out to courthouses and researching titles.” To limit the outlay, the company is creating a digital marketplace for the reports owned by oil companies and regional companies in the report business. It is raising money to hire software developers and salespeo-ple to expand this resale market.

All these businesses are after niches that require limited capital. Compared with the enormous scale of the oil indus-try, the money backing the Surge startups is tiny—the amount raised by the first class of companies was hardly enough to drill and complete two shale wells.

To support the 12 ventures in Surge’s second class of startups, the program’s backers put up USD 1.2 million, with one-third of the money covering the operation and the rest supporting the companies—it pays for them to live in Houston for 3 months and to work together in an open space where each startup has a cubicle. The goal is to create a supportive environ-ment offering useful information, advice, and inspiration through what can be a lonely process of starting a business.

Improving the OddsSurge is modeled after similar ventures in tech centers such as California’s Silicon Valley. The goal is to improve the odds for new ventures by offering support, train-ing, and advice from experienced men-tors, some of whom are investors and many working for major oil com panies. The process often leads to changes in plans, sometimes complete changes in their direction, which is known as a pivot.

Among the mentors is Gene Ennis, best known as the chief executive offi-cer of Landmark Graphics during a rapid growth period for the innovative seismic software company that was acquired by Halliburton. He was involved in several startups and knows the odds.

“Based on data gathered in the ven-ture capital (VC) business, out of every 10

Ariel Sella, a Surge alumni starting a business accelerator in Israel, talked at Surge Day about the opportunities created by the growing number of sensors transmitting data over the Internet.



startups backed by investors, one will be a home run,” Ennis said, adding, “It might be one in 20 depending on the economy and other things we cannot control.”

These entrepreneurs were look-ing for investments from venture capital firms that have become more selective. “If you look at the ones VCs out there today are doing what they are doing in a much more conservative way than 20 years ago,” Ennis said.

On Surge Day, the goal for nearly all the members of the class was raising money. The one exception was Waveseis. The two-person company is built on an algorithm created by Mark Roberts, a former BP research geophysicist. That formula is the basis for a program designed to create more accurate images showing oil and gas targets beneath thick salt layers.

So far, Waveseis’ business plan has required a huge investment of Roberts’ time, but not much cash. “Mark plans to use this to get into the business,” said Ennis, who is advising the venture. The goal is to use revenue from the first pro-gram to pay for a series of improved seis-mic processing software designed with the needs of a select group of clients in mind.

What Roberts lacks is access to the field data to demonstrate he can cre-ate more accurate images of reservoirs below salt layers. So far, the evidence is limited to images created with synthetic data sets simulating conditions found in the ground. Roberts knows from experi-

ence that they are always clearer than the real data.

Getting the data he needed to cre-ate the image and verify its accuracy was more difficult because Roberts also needed permission to show the results to potential customers. “It is always a chal-lenge to get oil companies to show their data outside their walls,” he said.

Oil and SoftwareThe Surge portfolio ranges from moni-toring the health of drilling equipment to creating online markets.

Secure Nok’s business plan is based on a different way of sniffing out mali-cious software (malware). Its focus is machine performance, analyzing the data seeking early indications that a drilling rig control system has been compromised.

Most defense programs are designed to block incoming threats by identifying programs with code associated with mal-ware. Malware creators can stay ahead of those defenses by changing the code used, with programs now able to reside unnoticed for years before attacking.

The monitoring and detection part of Secure Nok’s programs looks for trou-ble in a different way—by comparing its current performance with data gathered during tests of the machines, as well as performance expectations learned from on-the-job performance as observed by an artificial intelligence program.

“Basically, our solution does not look for known attack patterns and sig-

natures, which is the common way used in existing monitoring solutions,” said Siv Hilde Houmb, chief executive offi-cer of Secure Nok. “Our solution evalu-ates the machine behavior to determine whether it is ‘normal’ or potentially ‘abnormal’ based on observations dur-ing testing, which is updated in the field using artificial intelligence methods to better observe and evaluate behavior.”

This diagnostic program is at the heart of Secure Nok’s incident-handling tool that advises operators on how to handle potential problems in a way that is supposed to minimize interruptions, Houmb said.

“The drilling market is our first focus, as we have partnerships and expe-rience in this space,” Houmb said. She said the company is collaborating with an equipment maker on pilots with a goal of building its software into the company’s equipment.

RunTitle is looking to change the way companies buy mineral rights, with an online market for title information. Based on their experience working as landmen, the company’s two founders created what they hope will be the online market for reports previously done to identify mineral rights owners.

The goal is an easy-to-use database covering all the significant unconven-tional oil and gas plays in the US, offer-ing data for a fraction of the cost of hir-ing someone to go to a courthouse and do a title search. The reports are from oil

THE INTERNET OF THINGS

The number of devices connected to the Internet has surpassed the number of people globally and is rising rapidly, according to a study by the network equipment company, Cisco. It predicted more than 6.5 connected devices per person in 2020, ranging from smartphones to oilfield sensors.

Year

2003

2010

2015

2020

World Population (billion)

6.3

6.6

7.2

7.6

Connected Devices (billion)

0.5

12.5

25

50

Connected Devices Per Person

0.08

1.84

3.47

6.58

Source: Cisco 2011.




companies and regional title databases seeking to resell old research.

As of June, the company said it had exclusive rights deals covering 15 million acres, or about 10% of its goal. While the reports are often several years old, updating those is far less work than start-ing from scratch.

“When 50 people have done this title search before, there is no reason for me to go back to 1830,” said Char-lie Wohleber, chief operations officer for RunTitle.

Similar thinking went into the cre-ation of the online metals exchange, known as Gmex. Jeremy Chapman said the idea for the company goes back to his time working as a metals buyer in the oil indus-try spending his days making one-on-one contacts with suppliers to fill orders.

Gmex’s goal is a widely used com-petitive online market in which approved vendors bid on orders from industri-al users. The challenge is to generate enough volume, so buyers and sellers can rely on it for a wide range of orders, which will justify the fees it needs to sup-port the business. While in the Surge

program, Chapman said they worked to make it more user-friendly, inspired by the car sales website Autotrader.com.

Skynet Labs is seeking to use cloud computing and the Internet to provide people in oil and gas with simple mobile ways to analyze data, said Tim Duggan, chief executive officer of Skynet.

The first products for the company were applications used by drillers built on widely used American Petroleum Institute formulas. The products include security to ensure this work cannot be viewed by network hackers, Duggan said. To grow, he is looking at sources of more widely used industry formulas, such as widely used ones in SPE papers, which Skynet can turn into an app in a relatively short period of time.

The company is working to move beyond a single-user customer base of engineers to operators and service com-panies by offering a cloud-based system. Now in testing, this system will allow multiple users to log in and view each other’s work in a secure online space where access is controlled and the work is saved.

An early inspiration for Duggan was seeing how his father, a drilling engi-neer, would do calculations using a per-sonal computer or paper, pencil, and a calculator. Duggan said, “The oil and gas drilling industry is drowning in Excel spreadsheets.” JPT

To demonstrate what its seismic processing software can do, Waveseis created these two seismic images. The one on the left was processed using a program that removes noise and distorts images beneath thick layers of salt. The one on the right used reverse time migration. It is seeking actual data to prove that its images are more accurate.

Distance, m

Dep

th, m

Waveseis RIT image

10000

4000

3800

3600

3400

3200

3000

10500 11000Distance, m

Dep

th, m

RTM image

10000

4000

3800

3600

3400

3200

3000

10500 11000

Tim Duggan, chief executive officer of Skynet Labs.


PRODUCTION RECORD


Saudi Arabian state oil company Saudi Aramco released its annual report in July, noting that it produced more oil and gas last year than ever before, and also raised its technical capabilities to new heights as part of it 2020 strate-gy to be a fully integrated energy and chemicals company.

The company’s annual production exceeded 3.4 billion bbl of oil, equal to an average of 9.5 million BOPD. “In 2012, we produced 3.479 billion bbl of oil, about one in every eight bbl of the world’s crude oil production and the most we have produced in a single year in our history,” Saudi Aramco said in its annual report.

“During 2012 at Saudi Aramco, we responded to market conditions by pro-ducing crude oil at the highest level in our company’s history,” said Khalid Al-Falih, president and chief executive officer of Saudi Aramco.

The company’s recoverable crude oil and condensate reserves have reached 260.2 billion bbl, while gas reserves reached 284.8 Tcf. “Our maximum daily sustainable crude oil production capac-ity remained at 12 million BOPD during the year. Our gas plants now have a gas

processing capacity of 13.23 Bscf/D,” the report said.

Gas production has also reached his-toric levels, as the company reported an 8.3% increase in output in 2012 com-pared with 2011 at about 3.924 Tcf/yr, the highest in Saudi Aramco’s history. The company also said that it produced 482 million bbl of natural gas liquids including 82 million bbl of condensates.

Crude oil exports increased 100 mil-lion bbl in 2012 to 2.52 billion bbl, with 53.2% exported to the Asia Pacific region followed by 16.5% to the United States, 7.4% to the Mediterranean region, and 5% to Europe.

In 2012, Saudi Aramco focused on exploring frontier areas in the Red Sea and complex reservoirs onshore and offshore. Discoveries included one oil field—Aslaf—and two gas fields—Sha’ur and Umm Ramil—bringing its total oil and gas field discoveries throughout its history to 116. Sha’ur was its first discov-ery in the marine portion of the Red Sea.

Unconventionals Advance Through exploration for unconven-tional resources, Saudi Aramco deter-mined that substantial shale and tight gas

deposits exist in Saudi Arabia, and made its first foray into the unconventional gas arena. “The Unconventional Gas Initia-tive will contribute to our strategic intent in many ways. Saudi Arabia’s supplies of unconventional gas will supplement its supplies of conventional gas resourc-es and help meet the kingdom’s energy demand,” the annual report said.

The company appraised three pro-spective areas for unconventional gas: the northwest, South Ghawar, and conden-sate-rich shale gas in the Rub’ al- Khali. “These efforts were aimed at acquiring the data needed to help us make the right decisions as to where and how to invest in order to accelerate the delivery of commercial production of unconven-tional gas,” Amine Nasser, senior vice president for upstream at Saudi Aramco, said during a recent industry conference. “These projects are part of our wider Unconventional Gas Initiative, which became fully operational in 2012 when multidisciplinary teams, made up of Saudi Aramco professionals and industry experts with extensive experience, began appraisal drillings.”

The report said that although “the cost of delivered unconventional gas is higher than most conventional gas, it is an important strategic and econom-ic choice for the company. Unconven-tional gas will serve as a substitute for higher value liquid fuels such as diesel, residual fuel oil, and crude oil that would otherwise be used to fuel the electric power and water-desalination needs of the kingdom.”

Boosting Tech Capabilities Saudi Aramco knows that further devel-oping its fields, increasing recovery

Saudi Aramco Oil and Gas Production Hits Historic Levels Abdelghani Henni, Middle East Writer

TAbLe 1—crude OiL PrOducTiOn in 2012

Year Annual Production (billion bbl)

daily Production (million bOPd)

2008 3.27 8.92

2009 2.89 7.91

2010 2.89 7.91

2011 3.31 9.07

2012 3.48 9.51

Source: Saudi Aramco

SaudiOilSept.indd 86 8/12/13 3:44 PM


rates, and exploring unconventional resources will require significant tech-nological advancement. Saudi Aramco is boosting technological capabilities as part of its 2020 strategy, aimed at ensur-ing the long-term sustainability of its production. It is investing more in devel-oping new technologies as well as invest-ing globally in startup and high-growth companies with technologies of strategic importance to Saudi Aramco.

The company inaugurated a new research and development center last year at Delft University of Technology in the Netherlands. The center, a part of Aramco Overseas Company, concentrates on geophysics research in near-surface characterization and data-driven seismic processing, and is one of two research groups closely aligned with a university.

The second research group, at King Abdullah University of Science and Tech-nology, undertakes projects related to biocapture, robotics, fuel technology, chemicals, membranes, and advanced

materials. The company is also opening several centers around the world in 2013.

In 2012, Saudi Aramco also reviewed all of its reservoirs, meticulously iden-tifying the crude oil mix that it will be able to deliver in the short and long term. “Going forward, we will rely on this infor-mation to help us continue to introduce

new best-in-class reservoir management principles for optimal development and production,” it said.

Saudi Aramco was granted 58 pat-ents last year, a record for the com pany. Examples of the innovations include technologies involved in locating and plugging lateral wellbores, flare stack and combustion apparatus, automat-ed real-time reservoir pressure estima-tion, advanced petrophysical algorithms fostering the shift from well-centric to model-centric workflows, and an illumi-nated directional wind speed indicator.

New technologies were enablers for the redevelopment of the Manifa field, the fifth-largest oil field in the world, in which five patents were filed, includ-ing one for the ILOOP that has potential international application for enhanced environmental cleanup. The company said it reduced sulfur dioxide emissions from its facilities by almost 70% between 2005 and 2012, despite the ongoing expansion of its operations. JPT

Table 2—ProducTion in 2012

Crude Production

3.5 billion bbl

Daily Crude Production

9.5 million BOPD

Annual Gas Production

3.9 Tcf

Daily Gas Production

10.7 Bcf/D

Proven Crude Reserves

260.2 billion bbl

Proven Gas Reserves

284.8 Tcf

Source: Saudi Aramco

SaudiOilSept.indd 87 8/12/13 3:25 PM

R&D ON CAMPUS


Industry/Research Collaboration Advances Oil and Gas TechnologiesMika Stepankiw, JPT Staff Writer

Universities are working hard to anticipate the demand for new technologies and techniques as oil and gas exploration delves into deeper waters, harsher climates, and unconventional fields. Numerous universities are teaming up with the industry on projects such as modeling software, heavy oil technologies, fines migration, drilling technologies, and foam to enhance oil recovery and production. Through these research collaborations, more efficient methods are being developed to meet the increasing global consumption of oil and gas.

Petroleum Engineering Department, Colorado School of Mines, US

The Petroleum Engineering Department at the Colorado School of Mines has a large undergraduate and graduate enrollment and a healthy mix of multidisciplinary research efforts including the Unconventional Natural Gas and Oil Institute; the Marathon Center of Excellence for Reservoir Studies; the Fracturing, Acidizing, Stimulation Technology Consortium; the Energy Modeling Group; the Unconventional Reservoir Engineering Project; and the Physics of Organics, Carbonates, Clays, Sands, and Shales Consortium.

One area of focus is the Routes to Sustainability for Natural Gas Development and Water and Air Resources project in the Rocky Mountain Region. For this project, the Petroleum Engineering and the Civil and Environmental Engineering departments are working with their sister school, the University of Colorado at Boulder, and seven other institutions in a Sustainability Research Network (SRN) funded by a 5-year grant from the US National Science Foundation. The mission of the SRN is to provide a logical, science-based framework for evaluating environmental, economic, and social trade-offs between the development of natural gas resources in the Rocky Mountain Region and the protection of water and air resources. The SRN plans to give the results of these evaluations to the public in a way that will improve policies and regulations governing oil and gas exploration. “Our goal is to find the balance between maximizing the development of natural gas and oil resources for the benefits of short-term reduction of CO2 emissions from power generation and transportation, national energy independence, and national job growth, while minimizing damage to water and air resources and risks to human health,” said Joseph N. Ryan, faculty director of the research project.

The department’s first task in the SRN is to assess the isolation of aquifers from gas- and oil-producing formations. The department is evaluating the possibility of losing isolation because of damage to the cement sheath from pressure testing, casing integrity tests, and other operations during the production cycle of an oil or gas well over a life cycle of up to 50 years. Using finite element analysis, the SRN is assessing the effects of the change in the in-situ stresses acting upon a cemented wellbore to determine the improvement or degradation of the annular seal during the well’s life cycle.

The second task is to estimate the probability of casing and cement sheath failure in production, intermediate, and surface casing strings. As part of this task, the SRN will review the consequences of failures, including volumes and nature of gases and fluids released into an aquifer. They will focus on “black swan” events—unlikely, worst-case scenarios and the possible effects of such an event.

The third task is to examine the possibility of fracturing into aquifers using fracture modeling software in addition to finite element modeling. The modeling will involve combinations of casing, formation barriers, and annular cement to determine if fractures could propagate into freshwater aquifers under a variety of conditions. The fourth task is to evaluate procedures used by various operators and service companies for “green” vs. “nongreen” well completions. The results will determine the best practices for green completion operations.

The broader impacts of this effort include improved public understanding of the effects of natural gas development on water and air resources and better decision making regarding the local effects as well as regional and national benefits of natural gas development.

RD Roundup.indd 88 8/12/13 3:46 PM


Institute of Drilling Engineering and Fluid Mining, Technical University Bergakademie Freiberg, Germany

The Institute of Drilling Engineering and Fluid Mining at the Technical University Bergakademie Freiberg was established in 1962 within the Faculty of Geosciences, Geoengineering, and Mining. The university offers a German diploma, which is equivalent to a master of science, in petroleum engineering. The curriculum covers engineering fundamentals and advanced subjects in drilling and production engineering as well as renewable and sustainable energy, including geothermal energy and underground storage of hydrocarbons, hydrogen, and CO2.

The institute has strong ties with the oil and gas industry through its association with oil, gas, and service companies and SPE chapters in Europe and around the world. Before joining the institute, faculty members work for a number of years to gain real-world experience in the industry. They maintain their connection with the industry by consulting, working on joint research projects, and teaching short courses.

The institute’s laboratories are fully furnished with the latest equipment and software. They have specialized equipment and advanced experimental setups for research in drilling fluids, oilwell cementing, data transmission in boreholes, and enhanced oil recovery. In particular, the laboratories have sophisticated equipment (Fig. 1) to measure the permeability of very tight rocks, such as caprock and rock salt, which are harder or more resistant rock types that often lay over a less resistant rock type. In 1919, the university took over the Reiche Zeche mine, which consists of 14 km of passageways at depths up to 230 m. The mine provides unique opportunities for research projects that require these specific conditions.

Current R&D projects include the following:

◗◗ Ultrahard materials for drill bit bodies and cutters

◗◗ Seismic prediction while drilling◗◗ Hydraulic and acoustic high-

speed telemetry systems

◗◗ High-pressure/high-temperature return permeability tests and drilling fluid management

◗◗ Energy fluid storage in salt caverns and porous reservoirs

◗◗ Stimulation technologies◗◗ CO2 storage in porous reservoirs◗◗ Enhanced oil recovery (e.g., microbial, thermal, and

acoustic wave stimulation)

Other major research interests include geothermal reservoirs and unconventional reservoirs, such as shale gas and submarine hydrate reservoirs.

Fig. 1—The laboratories in the Technical University Bergakademie Freiberg in Germany are furnished with the latest equipment and software. The equipment, shown above, can determine the tightness of a rock in unsteady-state conditions to simulate field environments.


R&D ON CAMPUS


Institute of Petroleum Engineering, Heriot-Watt University, UK

Research activities at the Institute of Petroleum Engineering at Heriot-Watt University span from exploration, through reservoir appraisal and development, to production technology. Within this broad spectrum, the institute is divided into 12 distinct research themes, each represented by an interactive grouping of academic/research staff and postgraduate research students. These themes include carbon capture and storage; enhanced hydrocarbon recovery; petroleum geoscience; and gas hydrate, flow assurance, and pressure/volume/temperature.

The Gas Hydrate, Flow Assurance, and Phase Equilibria Pressure/Volume/Temperature Research Group consists of approximately 20 staff and students with expertise in chemical engineering, petroleum engineering, geology, and physics. The research team seeks to address various aspects of flow assurance and gas hydrate development, including kinetic hydrate inhibitor evaluation; avoiding gas hydrate, wax, and asphaltene problems in petroleum production and transportation; design and testing of low dosage hydrate inhibitors, hydrate monitoring, and early warning systems; and the natural occurrence of hydrates in sediments.

The research group’s activities are supported by the Centre for Gas Hydrate Research, which was formed in 2001, and the Centre for Flow Assurance Research, which was formed in 2007. The research group collaborates with the industry through four joint industry projects and receives support from 25 companies. Current research is being developed through five ongoing projects: gas hydrates and flow assurance; reservoir fluid studies; low dosage hydrate inhibitors; hydrate safety margin monitoring and early detection systems; and impact of common impurities on CO2 capture, transport, and storage (a collaborative project with Mines ParisTech). Research activities have resulted in generating new understanding, novel experimental data, and extensive test facilities including five well-equipped laboratories and have led to more than 200 papers published in peer-reviewed journals and presented at technical conferences.

To address the increasing industrial demand for technical support, Hydrafact, a Heriot-Watt University spin-off company, was formed in 2006. The company is based in the Heriot-Watt University Research Park and has eight full-time and seven part-time staff members. Results of studies by the Gas Hydrate, Flow Assurance, and Phase Equilibria Pressure/Volume/Temperature Research Group have led to the development of three tools that are being commercialized by Hydrafact under license from the university: HydraFlash, HydraChek, and HydraSens.

HydraFlash consists of comprehensive software capable of modeling a wide range of scenarios in reservoir fluid systems. It can be used by chemical, process, reservoir, and production engineers for a variety of phase equilibrium calculations, covering systems with and without gas hydrates. The software is currently being used by a large number of oil, gas, and service companies. HydraChek and HydraSens are being developed as joint industry projects. HydraChek monitors hydrate safety margins by providing the actual concentration of hydrate inhibitor and salt through downstream analysis of produced water samples. This information can be combined with operating parameters to allow the operator to continuously monitor and optimize inhibitor injection rates. HydraChek has been successfully deployed in many fields around the world, and an online version is being developed by Hydrafact with support from Total E&P UK and Statoil Petroleum. HydraSens detects early signs of hydrate formation in hydrocarbon production systems by analyzing compositional changes in produced gas to detect small amounts of hydrate forming.

RD Roundup.indd 90 8/19/13 10:14 AM

JPT • SEPTEMBER 2013

Petroleum Engineering Program, Petroleum Institute, Abu Dhabi

Although the Petroleum Engineering Program at the Petroleum Institute is relatively new in the region, it has become regionally and internationally known because of its staff, undergraduate and graduate students, and state-of-the-art laboratories. Accredited by the Accreditation Board for Engineering and Technology, the program offers master of science and master of engineering degrees and has plans to offer a doctoral program in the near future.

The program offers a wide range of technical courses with a focus on applied engineering and decision-making tools to prepare students for global challenges in the energy sector. It benefits from direct access to real field data and examples through its strong affiliation with Abu Dhabi National Oil Company (ADNOC), and other companies, including Shell, BP, Total, and Japan Oil Development.

The program has several major projects with industry collaboration, one of which is the Smart Water Flood Project funded by Abu Dhabi Company for Onshore Oil Operations (ADCO) and led by Hemanta Sarma. The aim of this project is to increase oil recovery by altering formation wettability through modification of the chemical composition of injected water in the reservoir. A second project is the Transition Zone Project led by Hadi Belhaj. Also funded by ADCO, the project focuses on investigating variation of oil saturation distribution in a complex reservoir and determining the optimum well completion mechanism. Funded by ADNOC and Total, Ali AlSumaiti leads a project on digital rock physics in collaboration with Mohammed Sassi from Masdar Institute. The main objective of the study is to develop a digital rock physics database for Abu Dhabi’s reservoirs to be used as a tool to generate accurate, fast, and cost-effective special core analysis properties. This tool will ultimately support reservoir characterization and simulation models. The program also collaborates on projects with partner universities, notably Stanford University, the Colorado School of Mines, The University of Texas at Austin, and Rice University.

Continuous global growth in the demand for oil and gas has ignited the drive to explore new opportunities and develop new technologies to meet the demand. Carbonate reservoirs in the United Arab Emirates are categorized as high-pressure/high-temperature with great heterogeneity and high acidity. As a result, ADNOC, in conjunction with the institute, will build a new research and development (R&D) center called the Petroleum Institute Research Center with the aim to solve these issues. The advanced laboratories have been designed to meet all technical challenges and health, safety, and environmental compliance. The research center is expected to be complete by the end of 2014. With this addition, the institute expects that the number of funded projects will increase rapidly as will the number of scholars with extensive industry and academic experience to work on these projects.


R&D ON CAMPUS


Australian School of Petroleum, University of Adelaide, Australia

The Australian School of Petroleum at the University of Adelaide offers education, training, and research in the upstream petroleum industry. The program integrates petroleum engineering, petroleum geoscience, and business decision making in one school. Its current research interests are

◗◗ Reservoir characterization, modeling, and simulation

◗◗ Unconventional resources, completion, and production techniques

◗◗ Fundamentals of flow in porous media, enhanced and improved oil recovery, formation damage, and geomechanics

◗◗ Sedimentology and stratigraphy◗◗ CO2 sequestration◗◗ Economic evaluation◗◗ Decision making and risk analysis

The school has well-established links with the petroleum industry and related government organizations. It is a node of the Cooperative Research Centre for Greenhouse Gas Technologies, a collaborative research organization focused on CO2 capture and geological sequestration.

One of the school’s key research projects involves fines migration-assisted technologies for oil and gas recovery. Very small particles called fines can drift and block the permeability of the well. This process, known as fines migration, may result from an unconsolidated or unstable formation or from using an incompatible fluid that frees the fines. This is the most common formation damage

mechanism that often challenges the economic viability of a petroleum development project and is often found in production and injection wells, drilling, waterflooding, and pressure depletion with water support.

Although the current theory of fines migration in petroleum reservoirs predicts a delay in the permeability response, laboratory tests demonstrate an instant response. A new theory developed at the school involves the maximum fines retention function and drift velocity for fines that model fines mobilization and allows for laboratory coreflood test interpretations, well impairment history analysis, and well behavior prediction. Laboratory and field case studies validate the new approach. The reservoir studies use corefloods, tests with rock fragments and cuttings, Z-potential, and scanning electron microscope data along with well history for reliable prediction, prevention, and mitigation of productivity decline.

Traditionally, fines migration has been avoided because of its potential for having a harmful effect on reservoir permeability. However, research suggests that the permeability decline effect provides a relatively simple method for water mobility control. The university proposes deliberately freeing natural reservoir fines by injecting low-salinity/high-pH water, which results in a decline in the reservoir permeability and a subsequent deceleration of the injected or invaded water. Laboratory and field data cases demonstrate a threefold to fourfold reduction in produced water and a 5% to 10% increase in the recovery of oil and gas (Fig. 2), indicating that natural or deliberately induced fines migration may significantly assist in oil and gas production.

Fig. 2—A new approach to fines migration by the University of Adelaide in Australia shows an improvement in oil recovery and water mobility control when fines are deliberately freed.

SPE9, Water Injection

SPE9, Polymer Injection

5-Layer Reservoir, Induced Fines

SPE9, Induced Fines

5-Layer Reservoir, Water Injection

5-Layer Reservoir, Polymer InjectionRec

over

y F

acto

r

Pore Volume Injected

0 0.2 0.4 0.6

50%

25%

0%


R&D ON CAMPUS


Center for Petroleum Studies, State University of Campinas, Brazil

The Center for Petroleum Studies (CEPETRO) was founded in 1987 in a partnership between the State University of Campinas and Petrobras to address an increasing demand for R&D in the oil and gas industry. With this partnership, the Department of Petroleum Engineering in the Mechanical Engineering College was also created along with a master’s-level petroleum engineering program.

CEPETRO facilitates collaboration between academic and industry professionals to find new knowledge and technologies for the sector and to contribute to the scientific and technological development of the oil and gas area in Brazil. During its 25 years of existence, CEPETRO has carried out more than 300 applied research projects and has had approximately 390 master’s and doctoral graduates.

Research is the flagship of CEPETRO activities. The center currently has 140 researchers with expertise in oil and gas involved in 65 financed research projects. The center’s infrastructure includes six laboratories on its premises and another 13 laboratories in institutes and colleges around the campus. Current research is concentrated in six fields in

◗◗ Reservoir characterization ◗◗ Well engineering ◗◗ Computational geophysics ◗◗ The production of oil and gas ◗◗ Reservoir engineering◗◗ Riser systems

CEPETRO’s reservoir characterization research focuses on investigating reservoirs from the microscopic scale (e.g., petrophysical features) to the macroscopic and megascopic

(e.g., geometry of bodies and architecture) scale, which includes the petrographical characterization of field rock samples and outcrop analogs; field investigation of electric, radioactive, and magnetic properties; and diagenesis, the study of chemical and physical changes to sedimentary rock after formation.

Research in well engineering covers basic and applied aspects of wellbore stability, directional wells and new techniques for drilling, well control and safety, operability of ships and drilling rigs, and production in harsh environmental conditions. Computational geophysics research involves the development and application of methods and algorithms linked to wave propagation. Seismic processing algorithms, such as image reconstruction and inversion of seismic data, are being studied to better understand reservoirs.

Oil and gas production research facilities, such as CEPETRO’s multiphase flow lab, focus on new techniques and technologies that improve production and flow assurance in onshore and offshore fields, while reducing cost through intelligent production management (Fig. 3). The main research projects in oil and gas production cover artificial lift, separation of gas/liquid/solid, use of intelligent systems, and the production and transportation of heavy oils.

CEPETRO’s research in reservoir engineering involves characterizing rocks from basic and special core analysis with a focus on fluid displacement mechanisms and their effect on reservoir rocks. Analysis is conducted through laboratory assessments of the rock fluid properties as well as reservoir modeling through deterministic and geostatistic techniques. Reservoir simulation research is a primary

focus, covering topics ranging from history matching core displacement studies to field production data.

In the study of subsea systems, operability issues in offshore rigs, subsea operations, and information processing during the drilling and intervention phases are studied. CEPETRO aims to investigate and develop techniques related to subsea production systems, subsea equipment, subsea pipes, and production risers. CEPETRO’s previous R&D projects have included the design and installation of template manifolds, floating production systems with dry completion, numerical and experimental analysis of hybrid riser system dynamics, and the life of steel catenary risers.

Fig. 3—The multiphase flow laboratory at the State University of Campinas in Brazil is used for research on improving oil production and flow assurance and reducing cost in onshore and offshore fields.


R&D ON CAMPUS


Alberto Luiz Coimbra Institute for Graduate Studies and Research in Engineering, Federal University of Rio de Janeiro, Brazil

Historically, the Alberto Luiz Coimbra Institute for Graduate Studies and Research in Engineering (COPPE) program at the Federal University of Rio de Janeiro (UFRJ) has had a strong R&D emphasis on petroleum engineering. The first joint effort between Petrobras and UFRJ was formed in 1977; this was invigorated by the discovery of huge deepwater reserves along the Brazilian coast and more recently in the pre-salt layers. These efforts have led to the creation of jobs and consulting projects as well as the production of several scientific articles. This year marks the 10th anniversary of the installation of the world’s largest ocean basin laboratory, which was designed and built by COPPE. The COPPE petroleum interdisciplinary program draws upon talent from several departments and laboratories including petroleum systems, offshore systems and structures, structural integrity, materials, dynamic positioning, submarine robotics, and computational systems.

Petrobras America, a subsidiary of the Brazilian state oil company, has been operating the Cascade and Chinook fields in the US Gulf of Mexico. The company deployed one of the world’s deepest floating production, storage, and offloading (FPSO) facilities—the BW Pioneer FPSO facility. During the review of these field developments, what was then known as the US Bureau of Ocean Energy Management, Regulation, and Enforcement required the continuous monitoring of mooring tension in the mooring system. To meet these requirements, Petrobras America contracted a primary monitoring system to directly measure mooring system tensions using gauged pins. However, an alternate

monitoring system was also required to indirectly determine tensions by measuring the FPSO’s turret.

For this, Petrobras contracted COPPE/UFRJ to help develop the alternate system. Calibrated numerical models were created to represent the mooring system, which were then analyzed by the numerical solver SITUA/Prosim, which was developed by COPPE and the Laboratory of Computer Methods and Offshore Systems in partnership with Petrobras (Fig. 4).

Considering the platform would incorporate a supervisory system to collect and store measured data (e.g., positions, tensions, sea states), the tasks assigned to COPPE/UFRJ included adapting the analysis software for offshore use and real-time processing of the measured data to calculate and record the line tensions.

The most critical task was building an accurate model of the existing mooring system. The tension data from the primary monitoring system was unreliable, so alternative calibration procedures were devised. Remotely operated vehicles were employed to provide position data for selected points along the lines, and this data was post-processed into an accurate representation of each mooring line.

Because it needed to operate continuously and without supervision, the alternate monitoring system had to also be fault-tolerant. Currently, the system is operational and working without interruption. The model can also be recalibrated and updated with new data from surveys or direct monitoring of the mooring system tension.

Fig. 4—The Federal University of Rio de Janeiro developed a numerical model to monitor tension in mooring systems for floating production, storage, and offloading facilities.

RD Roundup.indd 96 8/14/13 8:37 AM


Department of Petroleum Engineering, Delft University of Technology, Netherlands

The Department of Petroleum Engineering at Delft University of Technology joins its fellow geoscience disciplines (geology, geophysics, petrophysics, geoengineering, and resource engineering) in the Department of Geoscience and Engineering. The petroleum engineering group has seven staff members, 25 to 30 doctoral and postgraduate students, and approximately 50 master’s-level students.

The department collaborates with subsurface disciplines, mathematics, and mechanical and chemical engineering. Cross-disciplinary research efforts include the close integration of geology, data assimilation, and reservoir engineering in reservoir characterization and the use of geophysics to monitor recovery processes and production from unconventional hydrocarbon resources. The department emphasizes innovation and complex experimental studies through its large and well-staffed laboratory. The department focuses on optimization and control theory applied to reservoir management, enhanced oil recovery, numerical methods of reservoir simulation, well productivity, and fundamental fluid and transport properties in porous media.

The department has been a pioneer in the development of concepts and techniques for “closed-loop reservoir management” also known as “smart fields” (Fig. 5). This involves optimization under uncertainty, data assimilation, and model order reduction. Two of the program’s key innovations in this field are the introduction of adjoint-based, robust, and two-level techniques for smart well optimization and of model reduction techniques. “Moreover, we have established fundamental insights in controllability, observability, and identifiability of reservoir flow, which serve as the basis for better algorithms for data assimilation and model-based production optimization,” said Jan Dirk Jansen, professor of reservoir systems and control.

In the field of enhanced recovery, foam piques the interest of Delft University researchers. “The complex fundamental properties of foam make it an excellent candidate for improving sweep of injected gas and production of oil during injection of gas for enhanced oil recovery,” said Bill Rossen, professor of reservoir engineering and chair of the petroleum engineering program. Foam research is divided into two themes: (1) developing improved experimental methods for its characterization and (2) improving modeling of the process based on insights from the characterization methods. Researchers develop more sensitive techniques for displacement experiments with foam using computerized tomography (CT) scans (Fig. 6). A new way to interpret CT data compared with prior techniques reduced the

estimate of the flowing gas fraction in foam by a factor of 70. Researchers also explore the effect of oil on foam in oil recovery. Chemically enhanced oil recovery research includes experimental studies and modeling of polymer flooding, alkali-surfactant polymer, and alkali-surfactant foam.

As part of a major CO2 storage research program in the Netherlands, the department focuses on transportation, reactions, phase changes, and petrophysics as well as how they affect the feasibility of CO2 sequestration in aquifers and depleted oil and gas fields. Micro-CT visualization revealed that during CO2 injection, salt precipitates at discrete locations distributed throughout the porous sample. Precise measurements of contact angles show that CO2 replaces water as the wetting phase on coal and some other minerals at high pressure.

Fig. 5—The algorithm for model-based production optimization developed by the Delft University of Technology in the Netherlands shows an improved net oil production while yielding significantly less water.

Fig. 6—Students prepare for a coreflood analysis using a computerized tomography scanner to study foam for enhanced oil and gas recovery at the Delft University of Technology in the Netherlands.


R&D ON CAMPUS


Department of Petroleum Engineering, Curtin University, Australia

Located in Perth on the west coast of Australia, Curtin University’s Department of Petroleum Engineering is at the hub of Australasian oil and gas production. The department offers bachelor’s, master’s, and doctoral programs in petroleum engineering and will begin a new 2-year master of subsea engineering program in 2014.

Closely aligned with the oil and gas industry, the department has a number of research projects with international companies including Chevron, Shell, Woodside Petroleum, and Apache as well as local Australian companies including Buru Energy and NorthWestern Energy. The department also works alongside the government, mostly with improving CO2 geosequestration (retention and wettability issues) and future drilling technologies. Curtin has four main areas of research in

◗◗ Reservoir engineering for understanding pore fluid flow

◗◗ CO2 geosequestration ◗◗ The geomechanics of fracture systems associated

with shale gas◗◗ High-speed, low weight-on-bit drilling technologies

In association with Deep Exploration Technologies Cooperative Research Centre concepts, the department anticipated that a future need of the industry is for a fast but inexpensive, high-technology drilling rig that can later be applied to shale gas fields and conventional oil and gas fields. The rig would need a small footprint to initially support rapid hole drilling to 2 km in the hard rock industry. To meet this need, Curtin developed a concept using a high-speed (6,000 to 8,000 rev/min), low weight-on-bit coiled tubing rig with

a high-speed downhole turbine driving a diamond impregnated bit. The coiled tubing is made of a light composite material and has imbedded sensors along its length for logging while drilling. The rock is inserted into a true triaxial cell that takes a maximum of 1 cu ft of rock to provide realistic downhole stress conditions (Fig. 7).

A CO2 storage project funded by the Australia National Low Emission Carbon Scheme seeks to better understand the effects of supercritical CO2 on the reservoir and shales for long-term storage of CO2. Of particular significance to carbon storage is the issue of imbibition and wettability, which allows improved reservoir simulation of the process. In parallel with this project, a second project seeks to understand the dehydration effects of CO2 when in long-term contact with impervious shale. The shale is exposed for 3 months or longer and then studied with micro CT scans (and other microscopy methods). This makes it possible to see if there are any changes in their mineralogy. Linked with this project is the National Geosequestration Laboratory, which gathers data from a test well 2 hours south of Perth close to Harvey, known as the Collie-South West CO2 Geosequestration Hub. Curtin’s hope is to turn the Collie-SW Hub into an industrial geosequestration site in a number of years provided that tests of the reservoir and its seal prove it is a suitable site for long-term, industrial CO2 storage.

Fig. 7—The initial high-speed laboratory test rig at Curtin University in Australia is used for conducting experiments in coiled tube drilling by using a high-speed downhole turbine, a diamond impregnated 2-in. bit, and low weight-on-bit characteristics.


R&D ON CAMPUS


School of Mining and Petroleum Engineering, University of Alberta, Canada

Strong support of industry and government funding for petroleum engineering research in the School of Mining and Petroleum Engineering at the University of Alberta enables researchers to work on real-world, diverse problems faced by the oil and gas industry. These problems include oil recovery from tight and shale environments by nonaqueous methods such as electromagnetic heating, thermodynamics, and multiphase behavior as applied to numerical modeling of thermal oil recovery; mature field development; formulating improved data-driven modeling approaches based on artificial intelligence and fuzzy logic for the design and optimization of thermal recovery processes; and use of nanometal particles in steam and solvent heavy oil recovery.

Tayfun Babadagli, professor of petroleum engineering and industrial research chair in unconventional oil recovery at the Natural Sciences and Engineering Research Council, is leading the Enhanced Oil and Gas Recovery and Reservoir Characterization research group to develop ecologically viable technologies for extracting or tapping unconventional oil reserves and resources (Fig. 8). Although Alberta’s oil sands contain an estimated 1.84 trillion bbls of crude bitumen, only about 9% (168.7 billion bbls) is recoverable using current technology. While proven technologies are successfully applied in surface extraction of mined oil sands, in-situ recovery of heavy oil and bitumen is still a considerable challenge due to the technological and economic problems. Through the development of advanced and optimal in-situ recovery techniques under this research program, the potential to recover the remaining reserves is within reach.

The program is designed to deal directly and extensively with ways to improve the efficiency of the depletion of heavy oil and bitumen from sands and carbonates by proposing and testing new methods and materials that do not exist in Canada. The research

program has gained industry support from Schlumberger, Canadian Natural Resources, Suncor Energy, Statoil, Husky, Petrobank Energy and Resources, Sherritt International, Apex Engineering, and Pemex.

The program is twofold. First, it focuses on improving existing technologies through experimental and computational modeling and visualization. Fundamental and applied research is conducted to understand the underlying mechanisms and physics of heavy oil and bitumen recovery processes, namely, thermal and solvent injection techniques. This leads to identifying the reasons for low recovery and inefficiency of these applications, including advanced techniques such as microscale (e.g., pore) to gigascale (e.g., field) experimental and numerical modeling studies. Second, the program tests new materials, tools, and techniques to improve the efficiency of the thermal and solvent processes with a focus on fluids/materials that respond electrostrictively and magnetostrictively, and react to changes in temperature or pressure. Under the research program, new techniques also include nonclassical modeling approaches such as random walk, particle tracking, and other types of pore or larger scale stochastic techniques.

The school also collaborates with German scientists through the Helmholtz-Alberta Initiative program. This project aims to assess the feasibility of obtaining geothermal energy for oil sands extraction and processing in the Fort McMurray area of Alberta. A hot dry rock system in granitic basement rock needs to be developed by hydraulic fracturing at a depth of 4000 m to 5000 m and injecting cold water to generate 60°C hot water for oil sands extraction for a period of a few decades at the rate of 50 L/sec. This research involves understanding fracture development in granitic rocks and optimizing the depth and injection rate to minimize cost while maintaining a given production temperature and hot water rate.

Fig. 8—The Enhanced Oil and Gas Recovery and Reservoir Characterization research group at the University of Alberta in Canada is working on ecologically viable technologies for extracting crude bitumen from Alberta’s oil sands. The team is led by professor Tayfun Babadagli, front center.



Petroleum and Natural Gas Engineering Department, Middle East Technical University, Turkey

The Middle East Technical University created the Petroleum and Natural Gas Engineering Department in 1964. The department has six full-time and eight part-time faculty members as well as 10 research assistants. Four laboratories are available for training and research: Core Analysis and Sample Preparation Laboratory, Pressure/Volume/Temperature Laboratory, Drilling Fluid Testing Laboratory, and Enhanced Oil Recovery Laboratory. The department’s research interests include

◗◗ Drilling fluids models◗◗ The environmental effects of drilling and production

activities◗◗ Reservoir characterization using CT scans◗◗ Underground storage of natural gas◗◗ CO2 storage ◗◗ Natural gas hydrates

While natural gas hydrates and CO2 storage have been studied independently for a long time, the department combined these two topics in one research project that focuses on the interaction between methane hydrates and CO2. The project aims to replace methane trapped in hydrate cages with injected CO2 to produce methane without affecting the stability of the hydrate structure. Other suggested

methane hydrate production techniques are based mainly on the dissociation of hydrates by reducing the pressure or increasing the temperature; however, these techniques add the risk of uncontrolled dissociation, which could lead to instability in the hydrate-bearing sediment.

Deep sea sediments have suitable conditions for the formation of hydrates. The Black Sea is one of the major identified natural methane hydrate regions of the world and may be a good candidate for CO2 storage in hydrate form. To determine the interaction of CO2 and methane hydrates and the sealing efficiency of methane hydrates, the department performed various tests including methane hydrate formation in both bulk conditions and within sand particles. A geological structure must contain an impermeable barrier to store huge amounts of CO2. Because of this, the department studied the sealing efficiency of methane hydrates and the long-term fate of the CO2 disposal under the methane hydrate zone by measuring the permeability of unconsolidated sand particles for several values of methane hydrate saturation and by injecting CO2 into the methane hydrates. The results suggest that the presence of hydrates sharply decreases the permeability of the unconsolidated sand system, while hydrate saturations greater than 50% may act as an impermeable layer.


MANAGEMENT


The past 12 to 18 months witnessed the oil and gas sector drifting away from the rule of certainty and the return of uncertainty. Uncertainty required more focus, deeper analysis, and operational determination. Deloitte’s fourth annual Oil & Gas Reality Check identifies five trends and delves into the fundamental characteristics of each trend: the sup-ply, demand, macroeconomic, regula-tory, cost, price, and competitive behav-ior factors.

Given the rise of shale gas resourc-es and with new countries entering the ranks of net energy exporters, some are proclaiming that a global revolution is at hand with fundamental shifts in ener-gy geopolitics because of newly found energy independence. A closer exami-nation of the development progress of countries with major shale gas resourc-es reveals a vastly different picture. Countries that can commercially pro-duce unconventional and convention-al gas seek higher returns by exporting or planning to export liquefied natural gas (LNG) to Asia Pacific countries that have historically agreed to long-term purchase contracts at oil indexed prices. The expected increase and diversity of LNG supply is spurring transition away from oil price indexation, and the rise of gas hub and hybrid price indexation.

The discovery of new resources across various geographies coupled with the technical challenges of developing those resources are softening govern-ments’ resource policies—an indicator of the degree of resource nationalism. As production efficiency rates and capa-bilities improve, will resource national-ism surge or will it pale in comparison

with the competitive rise of national oil companies (NOCs)? How companies react to and deal with this uncertainty is changing the notion of a singular busi-ness model and giving rise to different business models.

Each of these questions and the five trends are discussed below:

1. Shale gas: A global or regional resource?

The success of North American shale gas has created interest in duplicat-ing the results in other countries. An April 2011 study by the US Energy Information Administration estimated that world shale technically recover-able resources outside the United States were 5,760 Tcf, sparking widespread interest in international shale. However, the presence of shale gas in the ground does not guarantee the unearthing of a fortune.

Given the greater technical chal-lenge of shale gas and higher devel-opment costs, exploitation of shale resources is not easily replicable in other markets. While some countries are mak-ing progress, over the next 1 to 3 years it will remain a largely regional resource with an uncertain impact on the glob-al market beyond this timeframe. Four countries with major shale gas reserves are representative of the distinct phases of resource development:

◗◗ Poland is struggling to maintain its nascent shale industry because of a recent reduction in the estimated size of its shale resources, as well as declining

company interest resulting from poor initial results.

◗◗ China is working diligently to provide an investment environment conducive to shale development, but given rising domestic demand and a challenging exploration environment, it is unlikely to become a shale exporter.

◗◗ Argentina experienced positive production results and is aiming to scale up production, bringing new shale basins online.

◗◗ The United States is home to the shale gas revolution and poised to globalize its shale resources through exports of LNG, assuming favorable exporting regulation and permitting.

The US shale gas revolution was 3 decades in the making with incremen-tal progress through multiple stages of development. Although other countries want to replicate this success, there is a long road ahead before they can begin to see the gas volumes and supporting infrastructure needed to dramatically lower domestic natural gas prices and create export opportunities.

While countries may enter into partnerships with shale-experienced companies, limitations such as low reserves per capita and steep demand curves can constrain countries from becoming shale exporters. Apart from the US’ pending exports of LNG, the reality is that shale will continue to be a regional resource with limited impact on the global market over the short term.

Top Trends in the Oil and Gas SectorAdi Karev, Global Head Oil and Gas, Deloitte Touche Tohmatsu

ManagementSept.indd 102 8/13/13 7:52 AM

MANAGEMENT


2. LNG pricing: The end of oil indexation?

The prospect of the US globalizing its shale gas resources through LNG exports has many observers (especially in Asia) hopeful that US LNG indexed to Henry Hub prices will also be exported, erod-ing the hold of long-term LNG con-tract price formulae indexed to crude oil. Anticipation has been heightened in light of recently announced Henry Hub-linked contracts, which could see Japan’s import prices in the range of USD 10 to USD 12 per MMBtu compared with USD 14 to USD 16 per MMBtu for oil-linked contracts. Rather than signaling a complete switch from oil to gas hub indexation for long-term LNG contracts in Asia Pacific, these recent develop-ments reflect a transition toward a pric-ing spectrum in which oil indexation is one of several pricing mechanisms used.

As diverse supplies enter the LNG market over the next 12 months and beyond, the dynamics of supply com-petition will drive transition away from contracts purely indexed to oil prices and at high oil-price parity in the Asia Pacific region. There will likely be a mixture of contract pricing approach-es—prices set lower from oil price par-ity, hybrid indexation, and full gas hub

indexation. Oil indexation will like-ly remain the predominant pricing approach because of concerns over gas and oil price volatility risk, and also because suppliers are able to offer value through nonprice terms, such as quality flexibility, supply security, and equity stakes in upstream projects.

US LNG exports will be a major catalyst for the transition away from oil price indexation. It is important to stress that not all US-sourced LNG will be indexed to Henry Hub prices, and pricing will be dependent on project economics, buyers’ price sensitivity, and the relative competitive landscape. On the other hand, even limited US LNG export volumes indexed to Henry Hub will be sufficient to spark competitive pricing among existing and up-and-coming LNG suppliers (Fig. 1). For Asia Pacific buyers, supply competition and diverse pricing approaches are welcome new developments.

3. Resource nationalism: Entering a period of low tide?

The recent discovery of new resourc-es and burgeoning demand in develop-ing countries have produced a new crop of supply and demand centers, making industry players sensitive to a poten-

tial rise in resource nationalism. We define resource nationalism through types of government resource policies and fiscal regimes. A country’s resource policy is either protective (no equity participation to low equity stakes in production sharing contracts) or open (concession contracts).

Our analysis highlights the part-nership opportunities between interna-tional oil companies (IOCs) and NOCs, moving beyond the adversarial aspects that colored IOC/NOC relationships in the past. Not only are we seeing ben-eficial, mutually dependent relation-ships between IOCs and NOCs, but NOCs themselves are playing a quasi-governmental role in terms of infra-structure development and transference of technical expertise to smaller play-ers in the value chain. This interplay has, in some cases, benefited IOC part-ners by deepening relationships in the countries where they operate and bet-ter assist them to withstand resource policy changes.

Resource nationalism should diminish in the short term until produc-ing countries advance in resource devel-opment, bringing a rise in restrictive resource policies in the long term.

The US, Canada, and Australia—leading the development of unconven-tional oil and gas resources—will con-

Fig. 1—Projected prices vs. oil price parity (real 2012 USD/MMBtu).

Source: Deloitte MarketPoint analysis, April 2013 reference case.

Brent price parity Henry Hub Japan LNG (spot price) UK NBP

US

D/M

MB

tu

24.0022.0020.0018.0016.0014.0012.0010.008.006.004.002.000.00

20122011 2013 2014 2015 2017 2018 202020192016 20222021 2023 2024 2025 2027 2028 203020292026

ManagementSept.indd 104 8/13/13 7:52 AM

MANAGEMENT


tinue with concession contracts and a stable taxation regime in the near term, but are already indicating a future direc-tion of restrictions on exports and for-eign direct ownership.

China, Argentina, and Brazil seek foreign partnerships to support devel-opment of newly found resources, bal-anced with the need to build local tech-nical capacity and capabilities. The countries will likely change contract-ing terms to extract a higher share from their resources, as new technologies mature and infrastructure is built.

Traditionally dominant producing countries, such as Russia, Libya, and Nigeria, will seek foreign investment and expertise to reverse declining rates of production in the short term, but they will likely shift toward majority gov-ernment ownership as economic pro-duction and cash flow improve in the long term.

4. NOCs: Capturing the playing field

The rise of NOCs as competitors of IOCs is a persistent narrative. NOC acqui-sitions reached an all-time high of USD 112.6 billion in 2012, representing 225% year-on-year growth, and con-stituting 45% of total exploration and production (E&P) mergers and acquisi-tions by value. NOCs are taking larger risks by buying undeveloped acreage and fields and initiating large acquisi-tions in countries such as the US, Can-ada, and Mozambique, showing that NOCs are taking the long view and glob-ally expanding for local resource devel-opment and technical capacity building.

A deeper look shows that NOC expansion is differentiated by oil vs. gas. Oil has been the predominant target of investment and E&P efforts, but this will shift to gas in the long term because of changes in end-use demand, resource availability, and price. Understanding how NOC expansion is differentiated by oil vs. gas will help define how IOCs and NOCs compete and collaborate.

In the short term, NOCs will con-tinue to dominate production in the conventional oil sector, and in the long term will increase investment in the gas sector, especially in offshore gas, shale gas, and LNG. Not only do these devel-opments impact IOCs, but also oilfield services majors that are emerging as important partners for NOCs, even as some NOCs are starting their own oil-field service subsidiaries. Overall, the industry will benefit as NOCs continue to invest heavily in research and devel-opment, expand in services capability, and transfer technical expertise to local development of resources.

5. Managing market complexity: Revolution of the play, evolution of the player

It is no secret that, in recent years, oil and gas companies have been forced into more challenging operating envi-ronments and become subject to more volatile and complex market conditions, rendering the term “business as usual” obsolete. Vertical integration was tra-ditionally seen as the winning business model, but the industry has become more fractured with diverse business models and nontraditional players, debunking the notion of a singular win-ning business model.

The types of business models employed by oil and gas companies also differ between sectors. The gas sector, which is dominated by growth in uncon-ventional resources and LNG, is facing greater vertical integration, while the oil sector is undergoing disintegration and specialization for smaller players.

In the past few years, four US inte-grated companies announced or com-pleted spin-offs of their downstream businesses; supermajors saw prof-it increases in their downstream seg-ments because of asset rationalization and growth in chemicals; and NOCs continued to expand their global refin-ing capacity. These varying paths show that vertical integration as the win-

ning business model in the oil sector is far from becoming a market certain-ty. Instead, vertical integration largely depends on aligning company strengths and strategy with local and global mar-ket conditions.

In the gas sector, marked by growth in unconventional resources and LNG, the entrance of nontraditional players, downstream players moving upstream, and large integrated companies expand-ing throughout the value chain seem to show that vertical integration is the win-ning business model. In the oil sector, vertical integration works for compa-nies with significant economies of scale especially considering the high capital intensity for unconventional E&P and LNG projects.

Overall, the industry has evolved to where market complexity is best man-aged through diversification of compa-nies, partnerships, and flexible busi-ness models. JPT

The full report that served as the basis for this article can be found at www.deloitte.com/energy.

Adi Karev is the global head of oil and gas at Deloitte Touche Tohmatsu. He has more than 25 years of advisory experience, including many years in Asia and multicountry advisory work for international energy and resources clients. Karev is responsible for the strategy, objective, execution, and operational management of Deloitte Touche Tohmatsu’s Global Oil and Gas Practice. His advisory work is focused on executive-level problem solving, including large strategic and transformational initiatives involving cultural, economic, and operational challenges of mergers and global expansions, and other major external events.

ManagementSept.indd 106 8/13/13 2:51 PM


Erik Vikane, SPE, is production manager for Statoil Oseberg East. He has 22 years of diverse experience in the upstream business.

Starting as a well-intervention engineer, Vikane then moved to reservoir engineering and has held various positions within reservoir management, early-phase development, exploration, and business development. His areas of interest include reservoir and asset management, reservoir performance and monitoring, and integrated uncertainty studies. Vikane holds an MS degree in petroleum engineering from the Norwegian University of Science and Technology. He serves on the JPT Editorial Committee and the SPE Reservoir Management 2020 Forum Committee.

“All models are wrong, but some are useful.”This famous quote by George E.P. Box illustrates both the challenge and the

appreciation of building models. Models are needed to predict future performance of an oil or gas field, but, at the same time, models are often biased and inaccurate.

Most investment decisions rely on our ability to predict and to plan the future, and, in that regard, nothing is more important than accurately modeling future well performance. Consequently, three of the four chosen papers address different aspects of this topic.

The first paper deals with ways to improve the accuracy of our predictions. It offers readers a rigorous checklist of questions to ask when developing reservoir mod-els to guide them toward less-biased forecasts.

The second paper deals with how we develop reservoir-prediction tools for asset management. Active reservoir management addresses the almost impossible task of maximizing short-term production while optimizing ultimate recovery. However, to evaluate the different reservoir-drainage mechanisms, one needs good models, and the more advanced the drainage mechanism is, the more crucial the model is. As an illustration, it is much easier to model a pressure-depletion scheme than to try to pre-dict a secondary- or tertiary-recovery process. Assessing and quantifying uncertain-ties as part of the modeling are becoming increasingly common, and this practice improves the ability to develop a sound decision basis.

The development of unconventional shale resources has further challenged the ability to predict performance. Prediction of such unconventional resources does not necessarily require new tools but rather new assumptions and new experience-based calibration methods. More than 40% of the papers I reviewed for this issue dealt with prediction of production and ultimate recovery of shale gas, which clear-ly illustrates the increasing interest in this topic and the current challenges faced by today’s petroleum engineers. The lack of history and of good analogs further adds to the uncertainty. I am sure that more research and the availability of more produc-tion data will enable us to develop better models and, hence, increase the accuracy of our predictions. The third paper provides great insight into our understanding of unconventionals. JPT

TECHNOLOGY

reservoir performance and monitoring

Recommended additional reading at OnePetro: www.onepetro.org.

OTC 23949 In-Well Distributed Fiber-Optic Solutions for Reservoir Surveillance by Juun van der Horst, Shell, et al.

IPTC 16866 Uncertainty Assessment of Production Performance for Shale-Gas Reservoirs by Jiang Xie, Chevron, et al.

IPTC 16505 Joint Inversion of Time-Lapse Crosswell Seismic and Production Data for Reservoir Monitoring and Characterization by Lin Liang, Schlumberger, et al.

1RPMFocusSept.indd 108 8/12/13 2:37 PM


This work presents a workflow that can be used to analyze and

forecast time/rate data of wells in low- and ultralow-permeability reservoirs. The key component of the workflow is the application of diagnostic plots to guide the analysis and obtain model parameters for a given time/rate relation. Once model parameters are obtained, the production profile is extrapolated to yield the estimated ultimate recovery (EUR) at a specified time limit or abandonment rate.

IntroductionThe starting point for any discussion of decline-curve analysis for unconvention-al reservoirs must be an understanding that no simplified time/rate model can accurately capture all elements of the performance behavior. In addition, no time/rate model can be expected to pro-vide a completely unique forecast of fu-ture performance or prediction of EUR. It is important to be both realistic and practical when attempting to character-ize production performance from sys-tems where the permeability is on the order of 10–500 nd, the reservoir flow system is complex, and, although the induced-hydraulic-fracture system en-ables (and dominates) the production performance, there is only the most rudi-mentary understanding of the flow struc-ture in the fracture systems.

It is essential that these conditions be established as a starting point. Not doing so will inevitably lead the analyst

to interpretations based on incorrect as-sumptions as well as significant bias. The authors assert that reasonable produc-tion forecasts and predictions of EUR can be made, but not in isolation, not solely looking at the data and the selected time/rate model. The analyst must consider the nature of the resource and the signif-icant uncertainty in the ability to apply simple time/rate relations to a very com-plex reservoir system.

As an attempt to better represent the general character of time/rate produc-tion data for a multistage-fractured hor-izontal well in an ultralow- permeability reservoir, numerous authors have devel-oped time/rate relations using certain specific bases to represent a particular scenario. These developments include the following time/rate relations:

◗◗ Power-law exponential model◗◗ Stretched exponential model◗◗ Logistic growth model◗◗ Duong model

Each relation has its own strengths, and, at this time, each of these mod-els can be described only as empirical; there is no direct link with reservoir-engineering theory other than through analogy. For example, the stretched ex-ponential model is essentially an infinite sum of exponentials, so the concept of adding the rigorous exponential decline to some limit could be thought to de-fine this model. The power-law exponen-tial model is essentially the same as the stretched exponential model (except for a constraining variable). At this point, we

must assume that the proposed models are essentially empirical in nature, and generally center on a particular flow re-gime or characteristic behavior.

Field-Case DataThe complete paper focuses on three dif-ferent shale-gas plays in North America. Field A is a formation composed of silt-stone and dark gray shale, with dolomit-ic siltstone in the base and fine-grained sandstone toward the top. The forma-tion of interest is a highly unusual, ap-proximately 400- to 500-ft-thick package of continuous gas-charged siltstone with very small clay content. The formation is slightly overpressured, with pressure gra-dients of approximately 0.50–0.65 psi/ft.

Time/Rate-Analysis RelationsThe basic definitions and diagnostic functions for time/rate analyses and a complete summary of the time/rate- analysis relations are given in the com-plete paper.

These relations are formulated as di-agnostic relations and are used to make long-term rate projections and predic-tions of EUR. As a matter of process, any given relation is calibrated against the historical rate and cumulative data by use of a diagnostic approach and the model extrapolations are made only from the end of the data (not the body of the data). This approach ensures that all extrapolations/projections are based on the actual (not model-based) cumulative production.

Diagnostics and Characteristic Time/Rate BehaviorThis section presents characteristic time/rate performance from six wells from Field A. The primary objective of this ef-fort is to demonstrate time/rate behavior of the wells with diagnostic plots with-out performing analysis corresponding to the play. Diagnostic plots used are

New Time/Rate Relations for Decline-Curve Analysis of Unconventional Reservoirs

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt.

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 162910, “Practical Considerations for Decline-Curve Analysis in Unconventional Reservoirs—Application of Recently Developed Time/Rate Relations,” by V. Okouma, SPE, Shell Canada Energy; D. Symmons, Consultant; N. Hosseinpour-Zonoozi, SPE, and D. Ilk, SPE, DeGolyer and MacNaughton; and T.A. Blasingame, SPE, Texas A&M University, prepared for the 2012 SPE Hydrocarbon Economics and Evaluation Symposium, Calgary, 24–25 September. The paper has not been peer reviewed.

RPM162910.indd 109 8/12/13 2:13 PM


the reciprocal of the loss ratio (D) and time (t), Arps decline exponent (b) and t, beta function (β) and t, and production rate/cumulative gas production (q/Gp) and t. Diagnostic plots have significant importance in our applications because these plots provide direct insight into our under standing of decline behavior.

For example, a straight-line trend of the continuously evaluated D-parameter [i.e., D(t)] vs. t on log-log scale could indi-cate power-law behavior that would yield the power-law exponential (or stretched exponential) function when the ordinary differential equation is solved for the rate function. Furthermore, from the contin-

uous evaluation of the b-parameter, it is possible to verify the hyperbolic behav-ior. A constant b-parameter trend [i.e., b(t)=constant] suggests hyperbolic rate-decline behavior; as such, it is possible to establish the value of the b-parameter in the hyperbolic equation. In addition, a constant β-derivative trend verifies power-law flow regimes such as linear or bilinear flow. These diagnostic functions involve differentiation of time/rate data, and, therefore, errors and inconsisten-cies associated with the data are ampli-fied in the derivative functions, which may prevent the analyst from establish-ing a unique interpretation.

The diagnostic plot of q/Gp and t provides significant diagnostic value be-cause it does not include any numerical differentiation and it serves as a comple-mentary diagnostic tool to the other di-agnostic plots.

From another point of view, diag-nostic plots are particularly useful while performing time/rate analysis. Each time/rate relation has more than two model parameters, and it is generally difficult to establish the values directly from production-rate data. In particu-lar, the log[D(t)] vs. log(t) plot is used to establish the power-law exponential and stretched exponential model parameters because these parameters are related to the slope and intercept values on this log-log plot.

The general procedure for time/rate analysis is to use the diagnostic plots and calibrate the parameters of each model simultaneously until an optimum (visu-al) match is achieved. This procedure en-sures consistency in the analysis and pre-vents the nonuniqueness associated with simply matching a single variable.

Fig. 1 presents the time/rate behav-ior of six wells producing in Field A. Shallower decline behavior and domi-nantly power-law-type flow regimes are observed throughout the production his-tory. When data are plotted on the log[qg/Gp]-vs.-log(t) plot (Fig. 2), almost all wells exhibit almost identical behavior.

The log[D(t)]-vs.-log(t) data are pre-sented in Fig. 3 (left axis), and it is ob-served that certain (but not major) dif-ferences exist in the slope values of these wells—which could be related to produc-tion characteristics. The log[b(t)]-vs.-log(t) data are presented in Fig. 3 (right

Fig. 1—Production-rate/time plot for all wells (Field A).

Fig. 2—Diagnostic plot: Gas-rate/gas-cumulative-production vs. time plot for all wells (Field A).

Diagnostic Plots: Field A (All Wells)Production-Rate vs. Time Plot (Log-Log Scale)

Time, days

Gas

-Flo

w R

ate,

qg, M

scf/

D

101 102 103 104100

101 102

102

103

103

104

104

105

102

103

104

105100

Data Functions Well A.1 Well A.2 Well A.3 Well A.4 Well A.5 Well. A.6

Diagnostic Plots: Field A (All Wells)(Gas Rate/Gas Cumulative Production) vs. Time Plot (Log-Log Scale)

Time, days(Gas

-Flo

w R

ate/

Gas

Cum

ulat

ive

Pro

duct

ion)

, qg

/Gp,

1/d

ays

101 102 103 104100

101 102

10–4

103

10–2

10–3

104

10–1

100

10–4

10–2

10–3

10–1

100100


RPM162910.indd 110 8/12/13 2:13 PM


axis), and these data suggest that the hy-perbolic relation could be applicable to model time/rate data because the b(t) trend exhibits a very gradual decrease with time and a constant b-value in the 2–3 range could reasonably be assumed. Fig. 4 presents the log(β-derivative)-vs.-log(t) trend, and a stabilization of data with time is seen, which suggests that

power-law-type flow regimes are being es-tablished. In conclusion, the diagnostic in-terpretation of time/rate behavior of wells in Field A was concluded with the remark that time/rate behavior is being dominat-ed by power-law-type flow regimes.

It is vitally important that the ana-lyst realize that the diagnostic analysis of production data is a necessary step. Al-

though some of the conclusions are quali-tative, the diagnostic analysis of multiple data functions ensures a degree of impar-tiality in the data analysis and helps at least qualify the uncertainty in the data, which will likely ensure that the relevant time/rate models are isolated and that analyses/interpretations are not attempt-ed that are not justified by the quality or nature of the given production data. It is critical that data diagnostics always be performed as part of the data analysis.

Application of the Time/Rate Models to Long-Term Production DataThis section presents a (relatively) long-term production-data example to inves-tigate the model behavior of the rate- decline equations considered in this paper. This field example consists of a tight gas well from east Texas (permea-bility values are estimated to be approx-imately 7.0 µd) with more than 7 years of production. For this case, we demon-strate our diagnostic interpretation pro-cedure for matching data and perform-ing forecasts.

All of the matches of production data with each of the time/rate models are performed simultaneously by cali-brating model parameters. Each of the models matches the data for the entire production history. In particular, when the log[qg/Gp]-vs.-log(t) plot is used, the models can approximate the data trend to a considerable extent (this rendering tends to force the impression of a linear relationship, which may not be the case). Therefore, the differences in EUR will be dictated by the long-term model behav-ior. This is where the differences between the time/rate models begin to emerge.

Duong’s model is based on the linear behavior of the (qg/Gp)-vs.-t data trend (on a log-log scale), whereas the power-law exponential, the stretched exponen-tial, and the logistic growth models exhib-it nonlinear behavior. This difference in behavior dictates that the EUR estimates from Duong’s model should (almost al-ways) be higher than those for the other models. On the other hand, when a termi-nal decline is imposed on the modified- hyperbolic relation, deviations from the linear trend are readily evident. The modified-hyperbolic and power-law ex-ponential have specific terms that limit

Fig. 3—Diagnostic plot: Computed D- and b-parameters vs. production time for all wells (Field A).

Fig. 4—Diagnostic plot: β-derivative vs. production time for all wells (Field A).

Diagnostic Plots: Field A (All Wells)Computed D - and b-parameters vs. Time Plot (Log-Log Scale)

Time, days

D-p

aram

eter

s, 1

/day

s

101 102 103 104100

101 102

10–4

103

10–2

10–3

104

10–1

100

10–3

10–1

10–2

100

101100


b-parameter

D-parameter

Diagnostic Plots: Field A (All Wells)β-derivative vs. Time Plot (Log-Log Scale)

Time, days

β-d

eriv

ativ

e, d

imen

sio

nle

ss

101 102 103 104100

101 102

10–2

103

10–1

104

100

101

10–2

10–1

100

101100


RPM162910.indd 112 8/12/13 2:13 PM


the overestimation of EUR; the Duong model does not. It is worth noting that, for methods that use a terminal decline, the prescribed value of the terminal de-cline is generally an arbitrary number and is often based on a company’s poli-cies or the analyst’s experience.

In the log[D(t)]-vs.-log(t) and log[b(t)]-vs.-log(t) data trends for this case, very strong linear behavior of the computed log[D(t)]-vs.-log(t) trend is observed, confirming the applicability of the power-law exponential time/rate model. It can be argued that the latest-time data are affected by the numerical-differentiation algorithm and, therefore, can be considered as artifacts. Neverthe-less, each of the models matches the data trends in its own fashion. The b(t) trend does appear to be decreasing with time (with the noted artifact near the end-point); and an average b-value can be in-ferred from the data behavior.

Time/Rate AnalysesThis section presents the time/rate analy ses for each well from a given shale play using each of the models specified in this study. It is worthwhile to note that each of the matches produced in this study are based uniquely on the authors’ interpretation of the model behavior. Dif-ferent matches with different EUR values can be obtained with similar probability.

It can be suggested that wells in Field A exhibit power-law-type flow re-gimes. The basis for this observation is mainly the signature on the time/rate plot and the near-constant character (at

intermediate and late times) exhibited by data on the log[β(t)]-vs.-log(t) plot. And almost all of the models match the entire production history. Differences in model behavior are observed at late times in the forecasts. Generally, EUR values from the power-law exponential and stretched ex-ponential relations are very similar (as should be expected). These models, along with the results from the logistic growth model, tend to provide conservative esti-mates across all wells. The Duong model and the modified-hyperbolic model al-ways yield the highest EUR predictions. A 5% terminal decline rate is used for the modified-hyperbolic relation.

In this particular case, the logistic growth model appears to provide the most conservative EUR values (quite comparable to those of the power-law exponential and stretched-exponential time/rate models).

Interpretation of ResultsThe authors’ interpretation of results is provided by presenting comparison plots of the EUR values predicted by each model. The power-law exponential model results were chosen as the refer-ence results, and EUR values from differ-ent models were compared with respect to those from the power-law exponen-tial model. This approach should identify any correlations or inconsistencies that might exist between models.

For Field A, the EUR values from the Duong model are consistently higher than the results from the power-law ex-ponential model. A comparison between

the power-law exponential model and the logistic growth model shows the EUR pre-dictions to be similar, with the exception of a single case. The next comparison con-siders the power-law exponential model and the modified-hyperbolic model. Some consistency in predicted EUR values is seen, but a couple of outliers suggest that the modified-hyperbolic relation will al-ways predict higher EUR values compared with the power-law exponential model. Finally, a comparison of the power-law exponential model and the stretched ex-ponential model reveals essentially iden-tical results, somewhat as expected be-cause these relations have essentially the same mathematical formulation. Almost identical results are seen because these two equations are essentially the same re-lations, and wells in Field A are not (yet) in the boundary-dominated flow regime after only a few years of production.

Conclusions◗◗ The D/t-and-b/t diagnostic plot

should be the primary diagnostic used to establish the well/reservoir character.

◗◗ The qg/Gp-vs.-t diagnostic plot is an excellent data check, and should be incorporated into diagnostic analyses; however, the expectation of a completely linear trend is optimistic.

◗◗ The β-derivative/t diagnostic plot is useful for establishing the existence of power-law flow regimes. JPT

RPM162910.indd 113 8/19/13 10:15 AM


Across the exploration-and-production (E&P) industry, several

projects were found to underperform compared to the promises made at the time of project approval. Investment decisions on upstream projects rely, to a large extent, on the robustness of the predicted ultimate recovery and production forecast associated with the chosen development concept. The challenge for the E&P industry is to ensure that project approvals are based on realistic forecasts. This paper is intended to increase awareness among the forecasters and the decision makers about pitfalls associated with production forecasting.

IntroductionRecently, an industry benchmarking consortium concluded the sixth of a se-ries of long-term production-attainment studies, which reviewed the produc-tion profiles of 59 major development projects from different hydrocarbon- producing regions. For the majority of projects, the forecasted production was not achieved.

Long-term production forecasts drive company strategies, portfolio choices, sales contracts, and sharehold-er promises. Too-optimistic forecasts re-sult in underdelivery of projects, with often far-reaching consequences. Too- pessimistic forecasts, on the other hand, may lead to undervaluation of assets.

The value of an E&P company is determined by the projects in its port-folio. Some projects in the portfolio are

mature, with a high likelihood of pro-gressing to the execution phase. Some projects are immature, with a possibil-ity of not reaching the execution stage (Fig. 1). For each project, it is impor-tant to have a realistic expectation of costs and production because this is the basis for business decisions. In addi-tion, for immature projects, it is equal-ly important to estimate the likelihood that they will be executed. At the port-folio level, this probability of matura-tion will lead to an appropriate expecta-tion of expenditure and production and will facilitate the making of higher- level business decisions. Fig. 2 shows how to combine realistic forecasting at the individual-project level and at the portfolio level.

Pitfalls of Production Forecasting Despite considerable efforts to prepare production forecasts, gaps between the forecast and the actual production are found in the majority of cases. Analy-sis of these gaps for a large number of E&P projects led to the following gener-ic issues.

Unrealistic Forecast Assumptions. The assumptions used for dynamic model-ing are frequently either optimistic or lack realism, resulting in over- or under-prediction of the production profiles. Project schedules often assume flawless execution and ignore or underestimate the potential for delays and unexpect-ed events. In reality, however, there is a high probability of activity slippage dur-

ing drilling, hookups, construction, and startup of new facilities.

Forecasters quite often assume that operational efficiency will be 100% dur-ing the life cycle of the project. However, significant deferments are seen because of operational constraints of various fa-cilities during the production cycle.

Human Bias. Forecasters and decision makers tend to be optimistic about their capability to judge outcomes of uncer-tain situations. They may underestimate uncertainty and have positively biased expectations about the consequences of their actions. They may ignore risks or underestimate the effect of risks on the forecast.

A tendency toward overconfidence may lead to overlooking certain realities. If a forecaster interprets data with a bias to confirm preconceived notions, it may result in an unrealistic outcome.

Reservoir-Modeling Limitations. Nu-merical simulation models approximate the production mechanisms of complex hydrocarbon accumulations. They suf-fer from inherent limitations in captur-ing the physical properties of reservoirs, wells, and process facilities. Simpli-fied models can overpredict produc-tion because actual geology and phys-ics are often more complex than can be captured realistically in a numerical model.

Instilling Realism in Production ForecastsThe following suggestions are useful for instilling realism in forecasts.

Realistic Forecast Assumptions. A base-case forecast should be found-ed on realistic assumptions about res-ervoir performance, project schedule, equipment availability, and production- system constraints.

Instilling Realism in Production Forecasting Decreases Chances of Underperformance


This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 155443, “Instilling Realism in Production Forecasting: Dos and Don’ts,” by Avnish K. Rajvanshi, SPE, Robert Gmelig Meyling, and Danny ten Haaf, SPE, Petroleum Development Oman, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8–10 October. The paper has not been peer reviewed.

RPM155443.indd 114 8/12/13 2:14 PM


The base-case-activity sched-ule should not assume flawless execu-tion across all project stages. Bench-marking the proposed schedule either against an actual project track record or against a schedule of analogous proj-ects should guide timelines for facility project completion, well delivery, and production ramp up. When selecting a base-case schedule, forecasters should examine whether the project is realis-tically achievable in the defined period and whether there is a 50% chance to beat the assumed schedule.

Neither perfect operational perfor-mance nor high initial uptimes for major new facilities should be assumed.

Forecast Reality Check. One should compare the forecasts with actual pro-duction on a regular basis. Reasons for significant deviations from forecasted performance should be investigated. When comparing forecasts with actual production, the essential first step is to understand any deviation in the imple-mentation of the plan.

Forecast assumptions and uncer-tainty ranges should be adjusted, tak-ing into account the latest production data, drilling results, and study out-comes. In the case of project slippage,

the forecast should be shifted toward the future.

Adjustment of Production Forecasts. Despite extensive technical work, pro-duction may be over- or underpredict-ed, particularly when forecasts are gen-erated from dynamic models. Most of the time, it is overpredicted. Therefore, there is a requirement to adjust the sim-ulation output to enhance the reliability of the forecasts. In the majority of cases, this adjustment will be a downward re-vision of the model forecast. However, there may be instances where an upward revision is needed.

Ideally, known uncertainties and risks should be captured in the dynam-ic model. Downward adjustment should address any residual risks and uncer-tainties that could not be covered in the modeling.

Model-derived forecasts can be con-ditioned by use of one or more of the fol-lowing techniques.

Calibration Against Histori-cal Performance. Model predictions should always be benchmarked against available field-performance data to en-sure that production forecasts are re-alistic. Appropriate adjustment fac-tors can be estimated from the gaps

between simulation forecasts and actual performance.

Actual production achieved for re-cent wells is generally an excellent benchmark when forecasting initial rates and ultimate recoveries for future wells.

Analogs. It is impossible to create a 100% accurate single deterministic res-ervoir model. Uncertainties in the pro-duction forecast will remain even when an excellent history match is obtained.

Analogs can assist in estimating well productivity and ultimate recov-ery for reservoirs with limited data. When comparing recovery efficien-cies predicted from a simulation study with that of an analog, it is important to identify those factors that control reservoir behavior. Specific reservoir classes can be inspected for possible analogs, such as carbonate reservoirs under waterflood.

Sensitivity Analysis. Sensitivi-ty analysis is used to determine which model parameters have the largest ef-fect on the history match as well as on the predicted production and re-covery. Some sensitivity parameters may have little effect during the his-torical period but have considerable effect on long-term predictions. This knowledge is valuable in estimating a

Fig. 1—Representation of an E&P company’s portfolio. For each project, a realistic forecast must be prepared. For immature projects, a probability of maturation is applied to achieve a realistic forecast at portfolio level. Note the size of the blue rectangle with increasing probability of maturation.

Fig. 2—Forecasting at individual-project and portfolio levels. The full rectangle represents the unadjusted forecasted volume from the forecasting tool. An adjustment is made for elements of uncertainty, which are not explicitly modeled. A further reduction is applied in the case of immature projects to represent the risk that the project will not be executed.

Explora�on

Appraisal

Investment Decision

Execu�onDevelopment

PlanningOpera�on

On Stream

Immature Mature Maturity

Project I

Project G

Project HProject E

Project D

Project F Project CProject B

Project A

Realis�c forecast for the individual projectRealis�c forecast for por�olio management

Realistic forecasting for individual projects

Unrisked volume

Maturation Riskrepresents the probability that a project will not be executed

Adjustment

represents unmodeled risks and uncertainties

Unadjusted volume

Realistic forecasting for portfolio m

anagement

Risked Volume (P50)

RPM155443.indd 116 8/19/13 10:16 AM


range of uncertainty for the predicted reservoir performance.

Most likely, there are multiple param-eters causing uncertainty in the forecast. The following steps are recommended:

◗◗ Identify the parameters that have the largest effect on the forecast. Check whether these parameters are interdependent. If parameters are interdependent, then a simple product cannot be applied and only the parameter having the greatest effect should be chosen.

◗◗ Estimate forecast-adjustment percentage for each of these (independent) parameters. For example, Adjustment 1=-20%, Adjustment 2=-15%.

◗◗ The total adjustment will be the individual adjustments applied in succession. Using the preceding example, the total adjustment will thus be calculated from (1-20%)× (1-15%)=68%, implying a total adjustment of -32%.

SummaryTo enhance the reliability of a produc-tion forecasts, the following suggestions are offered:

◗◗ Be realistic in assumptions. ◗◗ Be aware of reservoir-modeling

limitations.◗◗ Carry out regular forecast reality

checks.◗◗ Adjust the simulation-derived

forecast by use of some of the

practical techniques explained in this paper.

◗◗ Get an external review of the forecasts.

◗◗ Do not use simulation output without considering appropriate adjustments. Never treat simulation models as accurate predictors of reservoir performance.

◗◗ Avoid bias in sharing information, during analysis, and when selecting and reporting.

◗◗ No arbitrary factor should be applied to adjust the forecasts. JPT

RPM155443.indd 117 8/19/13 10:16 AM


The K field is one of the more developed deepwater fields

currently going through development in Malaysia. It has an excellent data set from which to optimize future development activities. In hindsight, it is clear that much more complexity exists than initially thought. As a result, uncertainty does not necessarily diminish at the start of production and a comprehensive collection and analysis of dynamic performance data are required in order to optimize recovery further.

Field Background and Geological SettingThe K field is a deepwater development located in 1330-m water depth offshore Sabah, Malaysia. The field was discov-ered by the K-1 well drilled to a depth of 3600 m on 30 July 2002 and marked the start of deepwater development in Ma-laysia. Five years after first oil, the field has more than 30 active wells including producers and injectors.

The K field is located in Block K (Fig. 1) and comprises the outbound tract of a major northwest/southeast- trending foreland fold-thrust belt that extends from Brunei to the Philippines and forms the margin of the North Sabah trough. Block K is dominated by fold-thrust structures. The reservoir section of the K field is dominated by mass-transport

deposits with interspersed complex reservoir-bearing turbidite deposits.

Subsurface Development ChallengesThe deepwater fields under development and study phases in Malaysia are usual-ly considered to have more or less simi-lar subsurface complexities and uncer-tainties. Among these uncertainties are level of heterogeneity, thinly-bedded-to-blocky sands, compartmentalization, fault intensity and behavior, reservoir connectivity, pressure and flow commu-nication across the field, injection re-quirement from early production time, sand/fines production and reactive shale,

wellbore stability, and commonly inade-quate available data at the time the devel-opment decision is made.

The typical type log in the K field shows the reservoir has been subdivid-ed into eight distinct reservoir packages labeled H110 through H150. In this ex-ample, the gross reservoir thickness (h) is 492 m with a net sand thickness of 50 m, giving an overall net/gross ratio of 0.102. Apparent from the type log is a large percentage of thinly bedded reser-voirs, characterized to be beds that are less than 30 cm thick.

Core data indicate that the thin beds ranging from 2 to 30 cm in thickness have porosity and permeability (k) compara-ble to those of the thick beds, an obser-vation further supported by well-test kh comparison with log-derived kh and nu-merous production-logging tool logs that have been run in the field.

The initial field-development-plan strategy was to develop the reservoir in three packages (H110–H115–H120, H130–H136, and H140–H145–H150) with updip production and downdip water injection.

Despite being in 1330-m-deep water, reservoir horizons are as shallow

Conformance Control and Proactive Reservoir Management Improve Deepwater Production


This article, written by Editorial Manager Adam Wilson, contains highlights of paper IPTC 16702, “Deepwater Production Improvement Through Proactive Reservoir Management and Conformance Control,” by Rahim Masoudi, SPE, Hooman Karkooti, SPE, Shlok Jalan, SPE, Anndy Arif, Keng S. Chan, SPE, and Mohamad B. Othman, SPE, Petronas; and Steve Burford and Philip Bee, Murphy Sabah Oil, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission.

Fig. 1—K field location in Malaysia.

Kota Kinabalu

SB-301

Labuan Island

K Field

Sabah

RPM16702.indd 118 8/12/13 2:16 PM


as 2400-m true vertical depth subsea. The development strategy had to employ multiple drill centers to access the oil, including wells drilled from the dry-tree unit or spar, and required subsea mani-folds for both production and injection.

Production- and Injection-Performance EvaluationThe field has a comprehensive data- monitoring system and reservoir- management strategy (Fig. 2). All wells have downhole pressure and tempera-ture gauges with real-time data access provided back to the office. The early interference detected in the downhole-gauge data proved invaluable in con-firming producer/injector connectiv-ity, particularly in the blockier sands. The reservoir- management strategy was based on the full voidage replacement by waterflooding and gas-cap gas injection (only in H150).

The implementation of the reservoir-management strategy has been based on weekly reviews including production, subsurface, and operations teams. The reviews incorporate voidage calculations, production performance, well-test data, and dynamic-model history-match updates as available.

The actual field performance after Phase 1 and during Phase 2, however, was not completely in line with the ini-tial 3D dynamic-model predictions. The

timing of water breakthrough was one of the key uncertainties because of un-known thin-bed extension and poten-tially uneven injection. The earlier-than-anticipated water breakthrough in some wells caused sand/fines instability and severe sand production, which led to cat-astrophic well failures and production loss after Phase 1.

Another event that added more complication to the dynamics of the field was out-of-zone water injection, which happened in several injectors. Although corrective measures were taken instant-ly, the extent of the healing process is un-certain and some crossflow might result within the field.

Considering high-pressure depletion and the unexpected-water- breakthrough pattern observed in some areas in the field partly because of heterogeneity, subseismic geological features, water- injection distribution, and thin-bed ex-tension, the connected sand volumes in the initial models were proved to be over-estimated. Many examples now exist in the field where sands disappear or thin or thicken dramatically within 100 m of well control. On the basis of the observa-tions so far, the classic view that uncer-tainties will decrease through time with more wells and dynamic data does not necessarily hold for all deepwater turbi-dite fields. The extension of the thin beds and the dynamic complications thereof

have always been and will remain a major source of uncertainty in this deepwater field development.

Injection-Performance AnalysisFor analyzing water-injector performance, the Hall plot and modified Hall plot in combination with other plots such as the Hall-plot derivative, well-performance-analysis plot, and injectivity index were used. Because all the wells were equipped with downhole gauges as part of the reservoir-monitoring plan, the Hall plot was generated on the basis of both tubing-head pressure and bottomhole pressure.

The Hall plot is a diagnostic tool for monitoring water-injection-well perfor-mance. Hall-plot analysis is conducted by plotting cumulative water injected vs. cumulative injection pressure, either bot-tomhole pressure or tubinghead pres-sure. A straight line with constant slope indicates the well is injecting consistent-ly. Any deviation from the straight line indicates plugging or fracturing effects. In order to look at the Hall plot more closely, a derivative of the Hall plot vs. cumulative water injection was also gen-erated. For a well performing consistent-ly, the derivative of the Hall plot will be a horizontal line, and any change in this horizontal line vs. cumulative water in-jection indicates plugging or fracturing.

On the basis of well-by-well injector- performance analyses during the life of the injection well, decreased injectivity was ob-served in some of the water injectors after prolonged shut-in or after being choked back. One possible reason for this kind of behavior is flowback of sand/fines during shut-in, which would block the pores at the sandface and reduce injectivity.

The kh distribution in three reser-voirs was predicted to be quite even; however, the observed water-injection rate into the H110–H115–H120 reser-voirs did not follow the ratio of the kh. This is thought to be primarily because of fracturing performance in the early part of the injection life of the well. The water-injection split and distribution sensitiv-ity to the injection rate raises questions regarding the water-injection distribu-tion in commingled sands on the basis of kh data. This kind of problem potentially can be addressed by using selective and smart water-injection schemes, which are being considered currently.

Fig. 2—Reservoir-monitoring and -management workflow. DHG=downhole gauge; VRR=voidage replacement ratio; GOR=gas/oil ratio; FBHP=flowing bottomhole pressure; PTA=pressure transient analysis; MDT=modular formation dynamic tester.

Objectives:

ProductionIssues:

SubsurfaceChallenges:

SurveillanceTools:

PerformanceIndicators:

OperationalResponses:

MaximizeProduction

Rates

MaximizeUltimateRecovery

Long TermShort Term

Effective Reservoir Management

Sand Management Achieve Downhole Sand Control

Manage Geological Risk Sweep and Zonal Conformance

PTADaily Production TestingDHG Monitoring

MDT Pressureand DrillingData (Sw)

Fluid Tracers,Production Logging

Success of Wells:Pressure and Rate Prediction,Breakthrough TimingSimulation History Match

InterferenceResponses(PTA and DHG)

VRR TargetsGOR LimitsFBHP

Intervention/Stimulation

Rate (Production/Injection)

Optimize Development Plan/Well Locations During Implementation

Infill Drilling

P*/PbarSkin

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18178 JPT-AOGR-HALF PAGE AD.indd 1 10/04/2013 17:38RPM16702.indd 120 8/13/13 3:01 PM


Production-Performance Analysis Because of the uncertainties and un-expected events in the field, different production-performance-analysis tech-niques were applied to provide a range of predictions of future field production. This analysis was also used to comple-ment and sense-check the dynamic 3D simulation-model results. Production-/injection-well performance analysis and decline-curve analysis (DCA) were per-formed on a well-by-well basis.

Wells with sufficient production his-tory were considered in the category of “existing wells.” DCA for each well was evaluated by two methods: log (water/oil ratio) vs. cumulative oil and oil rate vs. cumulative oil.

Wells with little or no production history were considered in the catego-ry of “new wells.” Carrying out DCA for these wells is not as straightforward as for those with sufficient production his-tory; therefore, a customized DCA was carried out.

For existing wells, a correlation was generated between measured oil rate and the capacity (kh) of the well. Capacity of wells in the new-well category was es-timated from the reservoir properties from static/dynamic models and by use of the previously mentioned correlation, and initial oil rates were estimated for the new well. To cover the range of un-certainty apart from the most likely ini-tial oil rate, low and high values also were estimated from the correlation. For es-timating the production on plateau and decline factor for new wells, statistical analysis of the DCA of the existing wells was used. To estimate the production on plateau, a cumulative distribution function of cumulative production as a fraction of estimated ultimate recovery (EUR) for each well was prepared.

On the basis of the production-performance analysis (DCA), the EUR is lower than the most likely figure of the field prediction based on the 3D dy-namic model. This has been translated to an average 8% lower ultimate recov-ery factor (up to 50 million STB) com-pared with the reported value from the 3D dynamic model.

The next stage of development is likely to focus on identifying, screen-ing, and ranking missed opportunities,

in terms of either unswept or unsupport-ed oil. The use of smart injection wells is being considered to optimize injection conformance and focus pressure support on the known areas of unswept oil.

Smart-Well-Design MethodologyThe K field is moving into the brownfield stage, and a Phase-3 redevelopment re-view is under way. As a consequence of the geological and stratigraphical com-partments, more producers might be needed; however, improving the reser-voir conformance and sweep efficiency may also assist in optimizing the number of wells. From the operational point of view, it makes more sense to free up the spar slots for producers and relocate in-jectors to subsea templates. This would serve to create better access to produc-ers for possible interventions or chemical treatments for reducing skin.

On the basis of the subsurface fea-sibility studies, the following objectives were defined:

◗◗ Improve reservoir conformance and reservoir sweep.

◗◗ Delay water breakthrough in new wells.

◗◗ Reduce/eliminate well intervention for subsea wells to reduce operational expenditures.

◗◗ Accelerate and increase oil-production rate, and maintain or improve reserves.

A comprehensive subsurface- opportunity-framing and well/zone-screening study was performed to arrive at candidate selection for the first field trial. Consequently, a study was conduct-ed on smart-well-completion design on the basis of the performance data and subsea-wellhead configuration and taking account of surface-facility considerations.

The following solution was proposed: ◗◗ Implement multizone selective

subsea water injectors.◗◗ Allocate the required water

injection into selected zones by means of choking interval-control valves.

Considering all the operational and de-velopment challenges in this field, the project team successfully adopt-ed various technical initiatives and fit-for- purpose solutions in different dis-ciplines such as drilling, completion strategy, sand- control methodologies, selective smart injection, and proactive reservoir-monitoring and - management planning. Fig. 3 shows the short- and long-term production and additional- reserves gains in this field as a result of this study. In addition, the study shows that there is a potential of achieving a 4% incremental recovery factor through increasing the well water-cut limit from 95 to 98%. This will be pursued by enhancing the topside facilities and water- handling capacity. JPT

Fig. 3—Short-term production profile after optimization efforts in different disciplines.

Optimized Case

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RPM16702.indd 121 8/19/13 10:17 AM


A microchip system capable of measuring temperature and

pressure over the entire wellbore was developed and tested in the field. When used in the field, tracers will be injected together with the drilling fluid. As the tracer travels through the wellbore, it will measure the temperature and pressure throughout the wellbore and store the data in the on-chip memory.

Prototype The prototype of the instrument system is shown in Fig. 1. The instrument sys-tem developed in this work includes two major components: the surface devices (Fig. 1) and the tracers (Fig. 2). A tracer (approximately 7.5 mm in diameter) con-sists of a small system-on-chip integrated circuit (SOC IC), which includes sensors, microcontroller, memory, transmitter and receiver circuits, and density-control material (hollow spheres), all encapsulat-ed in a protective-chemical-coating shell. The surface devices include an initia-tor to reset the circuit on the tracer be-fore the tracer is injected into the well-bore, and a data collector to retrieve data from the tracer’s on-chip memory when the tracer is carried back to the surface by the drilling fluid. The initiator and data collector will use wireless commu-nication to reset the circuit and down-load data from the tracer, respectively. A magnetic tracer separator (see Fig. 1) will be installed after the data collector to recycle the tracers. A lithium cell (bat-tery) used in the tracer contains stainless

steel, which can enhance the separation of tracers from the drilling fluid in the magnetic tracer separator.

When used in experiments or in the field, tracers will be injected together with the drilling fluid. Before a tracer is injected into the flowline, it passes through an initiator, which will reset the circuit for recording data. As the trac-er travels through the wellbore, it will measure the temperature and pressure throughout the wellbore and store the data in the on-chip memory at a sam-pling rate set by the initiator. When the

tracers are carried out of the borehole by the drilling fluid, they will pass through a data collector (controlled by a computer) through which the tracer will communi-

Distributed Microchip System Records Subsurface Temperature and Pressure


This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 159583, “A Distributed Microchip System for Subsurface Measurement,” by Mengjiao Yu, Sufeng He, Yuanhang Chen, Nicholas Takach, SPE, and Peter LoPresti, The University of Tulsa; and Shaohua Zhou, SPE, and Nasser Al-Khanferi, SPE, Saudi Aramco, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8–10 October. The paper has not been peer reviewed.

Fig. 1—Schematic of the instrument system.

Fig. 2—Schematic of the tracer.

Data Collector

Initiator

Magnetic Tracer Separator

Mud Return

Control Computer

Tracer

TracerInjector

Wellbore

Drillstring

Mud Pump

Alternating ValveTracer-Injection

Pump

MagneticRing

Tool Joint

≈7.5 mm

≈0.5 mmHollowSpheres

ProtectiveCoating

Sensors

µ-Controller/MemoryTransmitter/Receiver Circuit

Power Supply(Lithium Cell)

RPM159583.indd 123 8/12/13 2:18 PM


cate with the surface devices to send the data stored in its on-chip memory.

Fiber-optic temperature and pres-sure sensors for harsh environments (up to 15,000 psi and 250°C) have been used in the field successfully during the last 10 years and will be integrated into the instrument system in this project. Other sensors can be integrated into the system when they are readily available.

When used in the field, magnetic rings can be placed on the tool joints (glued to the surface of the pin). An on-chip magnetic sensor can be fabricat-ed on the SOC IC. As the tracer travels through the borehole, it could sense the weak magnetic field around each tool joint along the drillstring. This informa-tion can be recorded in the on-chip mem-ory and used to determine the real-time location of the tracer in the wellbore.

SOC IC and Surface Devices. The device used in the initiator and the data collec-tor is the same, a surface-device reader and writer module. The surface-device reader/writer and the tracer commu-nicate through the wireless magnetic channel. The system can work in fully duplex mode or in half-duplex mode. In duplex mode, both the reader/writer and the tracer can transmit and receive si-multaneously at different frequencies. In half-duplex mode, the reader/writer and the tracer transmit and receive at dif-ferent time slots. Half-duplex mode can lead to simpler implementation at the expense of slightly slower communica-tion rate in this particular application.

Each tracer has its own identifica-tion, and thus can be logged separately.

The built-in lithium battery is recharge-able, allowing the tracer to be used many times.

Fiber-Optic Sensor. Currently, fiber- optic sensors are commercially available that are capable of measuring pressure and temperature up to 15,000 psi and 1,000°C, respectively, using a variety of methods. However, current realization of these sensors, including packaging, is not suitable for the current applica-tion. The focus, therefore, is the adap-tation of proven sensor concepts to the unique environment and operating lim-its of the tracer.

One potential sensor technology is based on a Fabry-Perot-interferometer (FPI) structure. FPI-based sensors can be made small, having a cross-sectional area not much larger than the fiber dia-meter (125 µm) and lengths on the order of 1 mm. Both the extrinsic FPI and the fiber FPI configurations will be investi-gated. Both configurations can measure temperature or pressure with minimal crosstalk from the other measurement, with proper design.

Protective Chemical Coating. Tracers need to be protected against harsh down-hole conditions. This can be achieved by encapsulating the stress-sensitive elec-tronic parts of the tracer into a pro-tective shell. The specific objectives of this protective shell are to shield the electronic parts of the tracer from high-pressure (up to 15,000 psi) downhole conditions, chemical attack, impact, and abrasion of the drillstring. The shell also plays a crucial role in reducing the ef-fect of temperature variation on the in-tegrity of the electronic parts. In addi-tion, the density of the protective coating should be low enough to ensure the mo-bility of the tracer. A literature review of chemical-coating materials reveals that special types of porcelain, ceramic, ther-moset, and composite materials have the potential to meet the required properties.

Laboratory TestingValidation of Tracer Passing Through Bit Nozzles. One of the major concerns of the tracer is whether it can pass through drill-bit nozzles. In order to prove that the tracers can do this, they were tested on a flow loop with a tricone drill bit at-

tached at the end. Tracers were injected into the flow loop by the tracer-injection system. Injected tracers traveled through the flow loop and then passed the drill-bit nozzles at the end of the loop. Results show that the tracer injection functions well and a controllable tracer-injection rate can be achieved. In addition, all trac-ers passed the drill-bit nozzles without any difficulties.

Temperature-Sensor Test. Changes in the temperature of mineral oil in which the tracer was immersed were record-ed every 20 seconds. At the same time, measurements by the tracer were taken at the rate of one sample per second. The integrated circuit was programmed to take a total of 500 data points. There-fore, the measurement took 8 minutes and 20 seconds to complete. After the test was completed, data collected by the tracer were transmitted to the data-acquisition system wirelessly. The tracer output is inversely related to the actual temperature change. These two curves were in a good agreement in terms of slope, response time, and curve trend.

High-Pressure/High-Temperature Survival Test. Tracer samples were placed in a chamber, and then pressure and temperature were applied to simu-late harsh downhole conditions. Tests were conducted up 12,000 psi and 100°C. Results show that tracer samples can withstand 12,000 psi and 100°C with-out undergoing any structural problems.

Tracer-Mobility Test. Another major concern about the tracer system is trac-er mobility. Tracers might travel a long distance in a wellbore and then have to flow back to the surface. In order to prove that the tracer can be transported by the drilling fluid, a tracer-mobility test was conducted on a full-scale flow loop. The full-scale flow loop had a 100-ft-long 8×4.5-in. annular test section. Tracers were injected from one end of the flow loop by use of the tracer-injection system developed in this study. After injecting the tracers, one can see that the tracers travel at a very fast speed in the test section.

Field Test The first field test was conducted in an onshore field in Saudi Arabia. Before in-

Fig. 3—The first three tracers to be deployed in the wellbore.

RPM159583.indd 124 8/12/13 2:18 PM

jecting tracers into the well, a tracer-retrieval system consisting of magnetic strips on the shale shakers was installed on the rig. In addition to the magnetic strips, an aluminum mesh basket was in-stalled at the end of the discharge line. The aluminum mesh basket serves as the last point to trap the tracers.

Testing Well Information. For the first field test, the main goal was to validate the concept and find out if the tracers can be carried out of the wellbore by the drilling fluid and then be retrieved on the shale shaker. To simplify the test pro-cedure so that we can focus on the major functionality of the microchip system, the tracer-injection system developed in this study was not used for the first field test. The tracers were deployed by di-rectly dropping them into the drillpipe during the pipe connection. Fig. 3 shows the first three tracers to be placed into the drillpipe.

A stopwatch was started when the tracers were dropped into the drillpipe to record the time needed for the tracer to return to the surface. Circulation of the drilling fluid was started right after the

pipe connection was completed, and a flow rate of 500 gal/min was maintained. It was estimated that the tracer should return to the surface approximately 50 minutes after the circulation started.

After injecting 13 tracers, seven trac-ers were found that returned to the sur-face. Out of the seven returned tracers, two tracers were intact and the other five were damaged.

Post-Test Processing. The two intact tracers were moved to the control room, and data were downloaded from one of them. During the download procedure, the circuit of the second complete tracer was found to be damaged. Pressure and temperature readings were downloaded from the on-chip memory of the intact-tracer circuit. It was observed that all the broken tracers had fractures on the plane where either the battery or the circuit board is located, which means that, by manufacturing the tracer in three layers, the integrity of the tracer was reduced. It is more difficult to make the tracer in one step, but, for greater mechanical strength, one-step manufacturing of the tracers may be required in the future.

Conclusions ◗◗ The concept of the microchip

was proved successfully. Operations such as initiation, deployment, fluid capability to carry the tracers back to surface, and retrieval methods were tested and proved to be successful.

◗◗ The prediction of time for the tracer to return to the surface calculated by the simulator was close to the recorded time.

◗◗ Two intact pieces were retrieved out of 13 pieces deployed. In addition, five broken pieces were retrieved at the surface. By improving the fabrication process, the survival rate should be improved.

◗◗ No plugging of drill-bit nozzles occurred during the tests. Therefore, more pieces can be deployed in the future to increase the retrieval rate.

◗◗ The overall return rate was greater than 50%, much better than expected. JPT

RPM159583.indd 125 8/12/13 2:18 PM


Paul Cameron, SPE, is a senior well-engineering adviser in the Global Wells Organization at BP. He is responsible for developing

and implementing well-engineering practices and building global discipline capability in the area of well-intervention engineering. Cameron has 30 years of experience in the industry, including holding a variety of engineering and leadership roles in the discipline areas of drilling, completion, and well-intervention engineering. He has worked in engineering and operations roles in Aberdeen and Alberta and, for the past 10 years, has worked in a global functional role and in leading technical communities of practice. Cameron serves on the JPT Editorial Committee and the SPE Europe Regional Training Advisory Committee. He holds a First Class BEng (Hons) degree in chemical engineering from the University of Bradford.

Achieve more with less. This is the rallying cry as our global energy journey plays out, whether in the onshore shale developments, in the deepwater basins, or in the fro-zen lands and waters of the Arctic. Two important levers for achieving this goal are improvements in well reliability and well productivity. Our industry needs to build and operate wells that deliver their design well productivity for their design life and do it consistently. Technology has a vital role to play to help deliver these improvements.

I began working in this industry exactly 30 years ago to the month. As a keen young petroleum engineer, I recall being amazed by the level and complexity of the technology deployed in our wells at the time—from the heavy iron at the wellsite to the mainframe computers filling a disproportionate amount of space in our suburban office block. Looking back, I could barely have dreamt about many of the technology solutions that we are using so routinely in our wells today.

Sometimes, solutions have come from an unlikely place—rooted in our operat-ing challenges. For years, we knew that downhole elastomers in subsurface tools were affected adversely by exposure to hydrocarbons. As a result of some innovative think-ing, this undesirable reaction has been successfully turned around to serve our needs in the form of engineered swellable elastomers. These are now being used extensively for zonal isolation and conformance management in horizontal multistage fracturing, as a core component of intelligent completions, and as a remedial solution to provide hydraulic isolation in various downhole components.

Fiber-optic technology is now transforming our ability to visualize the subsur-face and manage well performance, including multiphase-flow monitoring through distributed temperature sensing. A related technology, distributed acoustic sensing, is providing advanced downhole monitoring that enables us to better understand sand production and improve the effectiveness of hydraulic-fracturing operations and well-integrity management.

In the area of perforating technologies, improvements in the understanding of dynamic underbalance perforating and integration of abrasive-jet perforating in hydraulic-fracturing operations are helping us to optimize well productivity from the outset.

I hope you enjoy reading more about how these and other technologies are pos-itively affecting the reliability and performance of our completions today. We have come a long way in the past 30 years. I would like to close by particularly welcom-ing all the newly recruited engineering and wellsite staff to our exciting industry. Your vision and innovative thinking will shape our continuing journey to achieve more with less. JPT

TECHNOLOGY

completions today


SPE 163290 Third-Generation Glass-Barrier Technology: Improving Well-Completion Integrity and Reliability by Rune Gimre, TCO, et al.

SPE 160160 Production Array Logs in Bakken Horizontal Shale Play Reveal Unique Performance Based on Completion Technique by Robert Boyer, ConocoPhillips, et al.

SPE 165141 Impact of Charge Type Used in Perforation on the Outcome of Matrix Acid Treatment in Carbonate Formations: Comparative Study by Ahmed I. Rabie, Texas A&M University, et al.

SPE 163344 Optimization of Cleanup of Limestone Production Zones: New Observations by Eric Davidson, Halliburton, et al.

2CTFocusSept.indd 126 8/13/13 7:08 AM


Over the years, hybrid systems have been installed in horizontal

wellbores to increase the number of compartmental sections for hydraulic fracturing because of the limitations of ball-actuated fracture sleeves. Experimenting with hybrid systems provides operators with the ability to optimize spacing of fracture stages along the horizontal section when sleeve technology alone does not allow for the desired number of stages. The costs are higher for operators to perform a hybrid-type completion, however, and this has driven enhanced sleeve technology to allow for all-sleeve completions.

IntroductionThe Bakken shale located in the Willis-ton basin covers an area that includes portions of North Dakota and Montana in the US and Manitoba and Saskatch-ewan in Canada (Fig. 1). An unconven-tional reservoir, the Bakken formation is one of the last giants to be discovered in North America. The US Geological Ser-vice estimates that the undiscovered US portion of the Bakken formation holds 3.65 billion bbl of oil, 1.85 Tcf of associ-ated gas, and 148 million bbl of natural-gas liquids.

Advances in horizontal drilling of extended-reach wells and in completion techniques have increased the amount of recoverable oil and gas. Wells drilled in the Bakken are typically drilled hori-zontally across two 640-acre sections, with laterals that can extend more than

9,000 ft. Two completion methods known for cost-effectiveness and high well efficiency that are used in these wells are the openhole-packer system and the sleeve one-trip system.

Openhole-Packer and Sleeve CompletionsOpenhole completions performed in the Bakken are commonly run as a one-trip system on drillpipe containing the fol-

lowing equipment: a hydraulic or me-chanical running tool, liner-top packer or liner-hanger system, openhole packers, fracture sleeves, and float equipment. Once the system is in position, the ap-propriate fluid is displaced, and the liner-top-packer is set; the running tool is dis-connected from the system and removed from the well. The openhole packers pro-vide compartmental isolation along the horizontal wellbore with fracture sleeves placed at each stage, forming a pathway for stimulation fluid and the production of hydrocarbons.

When the pumping equipment is mobilized, a series of balls is dropped (in order of smallest to largest) that will land on corresponding ball seats starting at the toe of the well, isolating previous-

Advancements in Completion Technology Increase Production in the Williston Basin


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 159586, “Advancements in Openhole-Completion Technology Increase Efficiencies and Production in the Williston Basin,” by John Paneitz, Whiting Petroleum, and C. Christopher Johnson, Matthew White, and George Gentry, Baker Hughes, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8–10 October. The paper has not been peer reviewed.

Fig. 1—Location of the Bakken shale in the Williston basin, with a structural cross section.

SASKATCHEWAN

MONTANA

NORTHDAKOTA

SOUTHDAKOTA

MANITOBA

Member Extents:Upper ShaleMiddle MemberLower Shale

WILLISTONBASIN

Cross-Section

ElmCoulee

OverpressuredArea

AntelopeBakken Type Log

Nesson Apt

Schematic Structural Cross-Section

Nesson AnticlineAntelope Field

Elm Coulee Area Three Forks (Dev)Three Forks (Dev)Lodgepole (Miss)

CM159586.indd 127 8/13/13 7:19 AM


ly fractured sections and shifting open the fracture sleeves. After the pumping is completed, the well can be placed on pro-duction. During the production phase, the balls that were pumped down the wellbore and used to open the fracture sleeves will flow off the ball seats and back up the wellbore.

Components placed in the open hole are specifically developed for multistage applications. The openhole packers are manufactured with a swellable elasto-mer, which reacts to oil-based fluids (die-sel) and expands out to the wellbore, cre-ating zonal isolation.

Fracture sleeves contain specifical-ly designed ball seats that are pinned closed using shear screws when installed in the well. Through the use of fracture balls, a differential pressure is created across the ball seat, allowing for an in-crease in tubing pressure that shears the shear screws, shifting the sleeves open to expose the fracture ports. The pump rates and types of fracture fluid need to be known before the fracture sleeves are installed to allow for the correct number of shear pins to be placed in the sleeves. A differential pressure is created across the seats from the high flow rates in the wellbore. In some cases, the smaller-internal- diameter fracture sleeves placed closest to the toe of the well will require a higher actuation pressure than those placed toward the heel of the well to com-pensate for the forces created during the fracture treatments.

The positive impact realized from a faster hydraulic-fracture process is a lo-calized wellsite benefit. On a larger scale, the operator realizes monetary benefits as well. The wellsite impact from spend-ing fewer days on location during the hydraulic fracturing is considered from both a health, safety, and environmen-tal standpoint and an operational-risk and cost-reduction standpoint. A short-

er fracture time minimizes disturbanc-es to local populations and lowers the amount of CO2 emissions. The opera-tor experiences more-effective use of company personnel.

Fracture sleeves have proved to be reliable and conserve water and time be-tween fracture stages. The cycle time be-tween wells and the additional number of wells that can be completed from the reduced number of days spent on loca-tion allow operators to increase produc-tion across the field by bringing more wells on line.

Recent Advancements in TechnologyIn 2007, a new packer technology was combined with existing fracture-sleeve capabilities to provide the necessary components for a multistage, one-trip completion in the Sanish field. This new packer technology was a swellable elas-tomer wrapped and bonded to casing joints. Depending on the choice in elasto-mer, the reaction will occur in either oil- or water-based solutions. It is common in the Williston basin to use elastomers that react with oil to swell and create an-nular seals.

The initial fracture-sleeve applica-tion was deployed in November 2007. Upon reaching the target setting depth with the completion, diesel was displaced along the horizontal section containing the openhole packers. Behind the diesel, a ball was pumped to a ball seat for set-ting the liner-top packer and releasing the running tool from the bottomhole as-sembly. With the completion in place, the rig was moved from location and prepa-rations for hydraulic fracturing began. Downhole temperature for this well was 210°F, requiring 3 days for the packers to form a seal against the formation.

The hydraulic-fracturing operations began by opening the pressure sleeve.

A pressure of 4,000 psi was applied to shift the pressure sleeve. The first stage of the fracture was pumped through this sleeve. The remaining seven stages were pumped through ball-actuated fracture sleeves. The entire fracturing treatment was completed in less than 12 hours. Fracture specifics included the use of 1,800,000 lbm of natural-sand proppant and 18,000 bbl of water pumped at rates of 30 to 40 bbl/min.

The initial production for this well was 1,323 bbl of oil and 2 MMcf of gas during a 24-hour flow test. During the next 30 days, the well averaged 818 B/D of oil production and 828 Mcf/D of gas production. In the winter months, the use of conventional perforating guns and composite plugs would have caused the completion process to take a minimum of 4 days.

Throughout 2008, the number of stages in the one-trip openhole- packer-and-sleeve completions increased to 10. Engineers realized that production could be increased if the spacing be-tween sleeves/packers (stages) could be reduced. In 2009, this was accomplished by creating and deploying hybrid com-pletions consisting of two technologies: the use of fracture sleeves for the toe section of the wellbore and the use of composite fracture plugs for isolation and perforating guns for communicat-ing with the formation during the re-maining stages (Fig. 2). The installation of the hybrid completion was relative-ly unchanged. For the sections of the wellbore that were to use a plug-and- perforation method, openhole packers were spaced out with casing joints. The operator would be able to benefit from the fracture-sleeve efficiencies during the first 10 stages, but would then need to pump down composite fracture plugs and perforate each section for the re-maining stages.

In October 2009, new fracture-sleeve technology was deployed that in-creased the number of stages in a one-trip openhole-packer/sleeve system to 24. In 2010, the hybrid-system ap-proach was expanded to include more stages as the optimal spacing in differ-ent parts of the Sanish field was eval-uated. During this time period, ad-ditional components of the wellbore evolved with industry-adopted pressure-

Fig. 2—Illustration of an openhole-packer/sleeve hybrid completion.

FloatShoe

FloatCollar

FracSleeve

Openhole Packer

Liner Hanger System

Casing Section for Plug and Perforation

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integrity-verification requirements and with longer- lateral drilling. Liner-top-packer- and liner-hanger-system choices are reviewed on the basis of vertical or horizontal tool settings, pressure-rating requirements (pressure-integrity-test requirements), and combined loading of installed equipment during hydraulic-fracturing operations. Software models are generated, and separate calculations are performed to determine resultant loading conditions from pressure-test-ing and hydraulic-fracturing operations.

Recloseable Fracture Sleeves. These sleeves have been designed to shift open and lock into the open position. During the life cycle of an unconventional reser-voir, there are opportunities to refracture

complete wells or wellbore sections to re-establish production. In June 2009, a packer/sleeve completion system was in-stalled with recloseable fracture sleeves. The proposal included hydraulicly frac-turing the well to produce hydrocarbons before returning to the well for in-field refracture development. The ball seats would need to be milled out before shift-ing the fracture sleeve to the closed po-sition and isolating the fracture ports. This would provide the full-bore internal diameters required to install composite fracture plugs and refracture each sec-tion by use of the plug-and-perforation method. Since the installation, additional information has been gained in regard to required spacing between compartments, and the refracturing has not occurred.

Monitoring Multistage FracturingProper spacing of the compartments cre-ated by openhole packers along the hor-izontal section is determined through analytical methods. One such meth-od uses microseismic tools, where geo-phone arrays monitor shear failure along pre- existing natural fractures on the basis of acoustic signatures. Moni-toring of the fracture propagation pro-vides data that can be used to verify de-cisions made regarding spacing changes between compartments and wells across lease sections (Fig. 3). A more-complex configuration, which provides addition-al data regarding the reservoir and hy-draulic fracturing, includes the use of downhole flow and temperature sens-ing. This type of monitoring can be achieved with distributed- temperature-sensing (DTS) or permanent-downhole- monitoring (PDHM) systems, which are either electrical- or fiber-optic-based. In April 2010, a 10-stage openhole- packer/sleeve system was installed with DTS and PDHM systems. Afterward, pressures and temperatures were monitored dur-ing the fracture of surrounding wellbores, real-time monitoring occurred during the fracturing, and post-fracture monitoring was available to validate the performance of the openhole systems, providing data needed for drilling plans in the Bakken and Three Forks formations. Other meth-ods applied during field- development planning include drillstem testing, core analysis, and implementation of logs to characterize the reservoir. JPT

Fig. 3—Microseismic image of Sanish-field Bakken drainage area.

CM159586.indd 129 8/19/13 10:23 AM


The careful planning and successful execution of a multistage-fracture-

stimulation completion in one of the first horizontal wells (KZN-F) drilled in the Amin formation in north central Oman instigated a step change in initial production rate and long-term deliverability from this tight-gas-sandstone reservoir. The operator and service company worked as a team, modeling the fracturing program after North American practices.

IntroductionMost of the natural gas in the Amin for-mation is locked up in low-permeability, extremely hard sandstone formations in very deep reservoirs. Drilling times of 3 to 4 months are typical for vertical wells, and fracture stimulation is necessary.

BP acquired the concession from the Sultanate of Oman in 2007 to en-gage in an appraisal of the block (shown in Fig. 1). Following appraisal, a full field-development license may be grant-ed to develop the block. The objective of the appraisal project is to evaluate the delivery potential of gaseous hy-drocarbons from four reservoirs: Barik, Miqrat, Amin, and Buah. There were two wells drilled by BP that tested the Amin formation in the field before this investigation. The KZN-C well was stim-ulated with a conventional crosslinked-gel fracture treatment, and the KZN-E Amin well was stimulated by use of a hybrid technique. The only other frac-turing technique that had not yet been

introduced to the Amin formation was a high-rate water fracture (HRWF), also known as a slickwater fracture. This technology, widely used in North America, had originally been planned for use in the Amin reservoir and had already been used successfully in the Miqrat reservoir.

Pumping and chemical costs are lower for an HRWF than for crosslinked-gel fracture treatments.

Challenges and SolutionsZone Selection. Six target intervals were selected for flow testing in the KZN-F well, with the goal of evaluating the efficacy of different reservoir-access and stimulation technologies, as well as determining which formation condi-tions would contribute to flow. These intervals were identified by use of a combination of mud logs, conventional openhole logging, and a microimaging log. Gamma-ray, resistivity, and poros-ity logs were used to differentiate zones in the Amin reservoir that might present more-promising targets. The microim-aging log proved to be valuable for iden-tifying fractures in the reservoir that could be targeted for stimulation. Frac-tures were categorized as faults, natural fractures (cemented or uncemented), or

North American Completion Technologies Unlock the Amin Tight Gas Formation


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164008, “Adopting North American, Multistage Fracturing and Horizontal Completion Technologies Starts To Unlock the Amin Tight Gas Formation in the Sultanate of Oman,” by Robert Clark, SPE, BP, and Kevin Mullen, SPE, and Stevanus Kurniadi, Schlumberger, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28–30 January. The paper has not been peer reviewed.

Fig. 1—An image of north central Oman, illustrating the location of the block and surrounding fields. Also visible are the various dune seas and the Hajar Mountains along the northern part of the Sultanate of Oman. (Background digital-elevation model from ASTER.)

100 km

CM164008.indd 130 8/13/13 7:19 AM


drilling-induced fractures on the basis of their appearance on the log. Fig. 2 il-lustrates some of the data available from the microimaging log used to target key wellbore objectives.

Reservoir Access for Stimulation. The liner was cemented in place with five fracture sleeves preinstalled to provide multiple access points for possible stim-ulation. These were conventional frac-ture sleeves designed to be operated in either uncemented or cemented comple-tions using a ball to shift the sleeve to an open position for stimulation. However, in this case, a backup method for opera-tion was used, implementing a shifting tool, run on coiled tubing (CT), to acti-vate the ports. These sleeves were placed in approximate positions in the liner to target zones with increased evidence of fracturing. Overall, three reservoir- access technologies were planned for this well: sliding sleeve, explosive-jet (shaped-charge) perforating, and abrasive-jet perforating.

Fracture Interference. One of the objec-tives in drilling a horizontal well, espe-cially in low-permeability reservoirs, is to facilitate conducting multiple transverse- fracture stimulations along the lateral section. However, each fracture may be subject to fracture interference.

In the KZN-F well, because there were other considerations used to select the perforations, perforation clusters were spaced in a single fracture interval

between 27 and 53 m apart, depending on the interest of the zone. The overall interval of each fracture stage was ap-proximately 100 m, simulating typical North American operations.

At every fracture interval planned with multiple sets of perforations, HRWF treatments were executed suc-cessfully. The actual perforation set that does eventually fracture within a given fracture interval may be influ-enced strongly by reservoir quality at that particular depth (e.g., by the stress or fracture gradient at different perfo-ration clusters within a given interval). This tends to support the theory that multiple sets of fractures are unlikely in a fracture interval if that length is less than the fracture height.

Wellbore Access. Both CT and electric- line-tractor technologies were evalu-ated in the KZN-FH2 well after con-sidering which options for achieving wellbore access were practically and financially feasible.

CT intervention is already well-known as a robust method of conducting intervention operations. This method holds advantages such as rapid mobili-zation and rig up/rig down, live-well in-tervention, and the ability to perform nearly all intervention services except real-time electric logging. The disadvan-tages of this method are depth accuracy, which is especially important during the appraisal phase of a project, and high daily costs.

Electric-line tractors use two to six drive sections, operated by electrical power from the surface, to move the tractor into the wellbore. Perforating, logging, and setting bridge plugs can be performed with an electric-line tractor while being monitored from the surface. This method has the advantage of excel-lent depth correlation, but it has limit-ed ability to put significant force down-hole, and it is also very expensive. The electric-line-tractor method was shown to have the best ability to perforate and set plugs at the preferred depth, but leftover fracture sand in the tubulars caused several major delays during the operation. In electric-line-tractor op-eration, the cause of the problem is the downhole force limitation of the tool.

Zone Isolation. There are two conven-tional methods that industry adopts in a cemented-liner completion in a horizon-tal well to achieve zone isolation: sand plugs and bridge plugs. In North Amer-ica, the most common method used today for isolation in cemented com-pletions is bridge plugs run with pump-down guns. A bridge-plug method for zone isolation was planned for KZN-F to avoid intervention delays while run-ning the electric-line-tractor. Six bridge plugs were set inside the wellbore. All of them demonstrated the ability to with-stand fracturing pressures during oper-ation. Apart from six that set perfectly, two more bridge plugs were not run suc-cessfully. One bridge plug was set while running in the hole, which required a milling operation. A second plug was ac-cidentally set in the riser before running in the hole. Analysis of that event deter-mined that the tension on the gripper elements was too low, which probably contributed to setting the first bridge plug accidentally.

Depth Accuracy. Compared with CT, an electric-line tractor offers much better control of depth accuracy. The operator can perforate, log, or place bridge plugs with excellent accuracy with a tractor. Furthermore, a tractor-set bridge plug provides excellent depth correlation for CT operations. If the bridge plug can be placed using electric-line measurement, the CT can tag that plug with reason-able accuracy. This was demonstrated

Fig. 2—Example of drilling-induced natural fractures and breakout at bed boundaries in a horizontal borehole in the Amin formation.

Drilling-InducedFractures

OpenConductiveFractures

Bed-BoundaryBreakout

CM164008.indd 132 8/13/13 7:19 AM


in the abrasive-jet perforations in Stage 4, which were on depth within 0.5 m on the basis of the known depth of the pre-viously tractor-set bridge plug.

Technology-Comparison Results In North America, evaluating the opti-mum system to use by a trial-and-error approach would involve trialing technol-ogies in several wells. However, to short-en this process, several comparisons were made in KZN-F, which included frac-turing technique, proppant treatment volume, and reservoir-access technique.

Fracturing Technique. To maximize the stimulation treatment, a technique that would maximize fracture half-length, but would attempt to limit the height growth, would be optimal for this for-mation. The potential for uncontrolled height growth would most likely ac-company a conventional crosslinked-gel fracture treatment, so a hybrid fractur-ing technique or an HRWF has appeal. A hybrid fracture, in this application, refers to the use of a linear pad stage, whereas the proppant-carrier fluid is a fully crosslinked polymer gel. An HRWF refers to treatment using water and fric-tion reducer; proppant-carrying capac-ity highly depends on the pumping rate and is not considered to be a significant contributor to flow conductivity.

There were six fracture treatments performed along the horizontal well-bore: one using a crosslink-gel fracture (Stage 1), one using a hybrid technique (Stage 5), and the rest using HRWF tech-nology (Stages 2 through 4 and Stage 6). From a production standpoint, the HRWFs performed significantly better than the crosslinked-gel fractures, pro-ducing 12 MMscf/D vs. 0.5 MMscf/D.

Treatment Volume. Measuring prop-pant volume per net pay zone could give an indication of fracture conductivity. In the KZN-FH2 horizontal well, which has the same formation properties along the majority of the horizontal wellbore, sensitivity to proppant volume can be compared between Stage 2 and Stage 3 fractures. Stage 2 was treated with 287,600 lbm of proppant, while Stage 3 received 196,600 lbm of proppant. Both were stimulated with an HRWF tech-nique. Following a commingled-flow test, multiphase production logging showed that there was no additional production achieved by using larger proppant mass. Stage 3 did have many more clusters of natural fractures to tar-get, as well as the interval with 50 bbl of mud lost while drilling. Further-more, Stage 6 produced approximate-ly the same gas rate as Stage 2 despite having zero proppant used throughout the job.

Reservoir-Access/Perforation Tech-nique. Three different access or per-foration techniques were compared in KZN-FH2: cemented fracture sleeves, explosive-jet perforating, and abrasive-jet perforating. Explosive-jet perforat-ing demonstrated superiority to cement-ed fracture sleeves when Stage 1 and Stage 3 were compared. Assuming the same magnitude of tortuosity per stage, Stage 1 had a total near-wellbore (NWB) friction pressure of 2,400 psi at 36.5 bbl/min after acid-wash treatment. This compares with Stage 3, which had total NWB friction pressure of 2,200 psi at 64.5 bbl/min after shooting only four sets of perforations, demonstrating a 28-bbl/min increase in injection rate at the same NWB friction pressure.

Stage 3 and Stage 4 were intended to compare explosive-jet and abrasive-jet perforation techniques. Both of the stag-es used four sets of perforations. There might be a slight advantage with abrasive jetting, in that it is more likely to cut a slot or elongated oval shape instead of a hole. In any event, Stage 4 measured NWB fric-tion pressure of 2,250 psi at 73.2 bbl/min, which is approximately the same NWB friction pressure value as Stage 3, but with a further 9-bbl/min increase in rate. Depth control was much better for Stage 4 because the nozzle was landed on a bridge plug set just below the target in-terval by an electric-line tractor. JPT

CM164008.indd 134 8/19/13 10:26 AM


Statoil, operating the Troll field in the Norwegian sector of the North

Sea, wished to run a deep sidetrack from the main bore in a multilateral well that would exit through the liner in the reservoir. Several zonal-isolation methods had been evaluated, but on the basis of previous experience Statoil decided to use swellable-packer technology. Testing revealed that this type of completion would exceed the necessary requirements. The installation was performed from a semisubmersible rig ahead of plan.

IntroductionThe Troll field lies approximately 65 km west of Kollsnes, near Bergen, Norway. Although the field historically has pro-duced large amounts of oil, it is now pri-marily a gas producer and contains ap-proximately 40% of the total gas reserves on the Norwegian continental shelf. The gas reservoirs, which are 1400 m below sea level, are expected to produce for at least another 70 years.

The massive Troll A platform pro-duces gas, while Troll B, a floating pro-cess and accommodation platform with a concrete hull, and Troll C, a floating process and accommodation platform with a steel hull, produce from thin oil- bearing layers in the Troll West reservoir. The thin oil layer is between 22 and 26 m thick in the Troll West oil province and is between 11 and 13 m thick in the Troll West gas province. In order to recover oil from the thin layer, it has been necessary to develop advanced drilling and produc-

tion technology. All of the more than 110 production wells to be drilled are hori-zontal wells. This process requires two-phase drilling.

The first phase drills down to the reservoir, 1600 m beneath the sea bot-tom, and then the second phase drills to 3200 m in a horizontal direction through the reservoir. Twenty-eight of the wells are multilaterals that have two or three horizontal laterals.

The well in question faced sev-eral challenges normally not seen in Troll multilateral completions, includ-ing standalone-screen completion with zonal isolation, well paths with doglegs and a completion total depth (TD) of more than 6000 m, top completion with zonal isolation and zonal control for four zones, and the need for dual pressure and temperature monitoring for all oil zones.

The lower completion had been de-signed with specially developed inflow-control-device screens that had been de-signed to allow running of a 4½×3½-in. top-completion inner string. Conse-quently, the reservoir had to be drilled with a 9½-in. hole. Three 7×8¾-in. swellable packers were designed for in-tegration in the screen blank pipe, iso-lating the reservoir into three separate oil zones and a separate gas gap. Screen-drag simulations revealed helical buck-ling for a one-stage lower completion to TD. Hence, a lateral-liner wash-down sys-tem (LLWDS) was adopted for a two-run installation. Using the LLWDS, 1000 m of drillpipe-conveyed 6⅝-in. screens could be run to TD and dropped off in the toe of the well. The remaining 3500 m of screens and blank pipe with zonal- isolation swellable packers could then be strung into the openhole liner top, pro-viding complete sand control.

The top completion was designed with three dual gauges. Also, three 3½×4½-in. cable swellable packers were spaced out in the top- completion inner string in accordance with the external lower-completion swellable

Intelligent-Well Completion in the Troll Field Enables Feed-Through Zonal Isolation


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 160060, “First Intelligent-Well Completion in the Troll Field Enables Feed-Through Zonal Isolation: A Case History,” by Bjørn Olav Dahle, Statoil, and Peter E. Smith, Geir Gjelstad, and Kristian Solhaug, Halliburton, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8–10 October. The paper has not been peer reviewed.

Fig. 1—Illustration of swellable packer with cable-feed-through capability in an intelligent-well configuration.

CM160060.indd 136 8/13/13 7:18 AM


packers. Three 3½-in. hydraulic flow-control valves were integrated into the top- completion inner string to allow individual-zone control inside the sand screens. Additionally, a hydraulically op-erated six-position gas lift valve was in-stalled below the production packer, al-lowing natural gas lift.

Feed-Through Swellable-Packer TechnologyPacker Design and Relevant Applica-tions. Swellable-packer technology com-prises standard oilfield tubulars with lay-ered rubber chemically bonded along their lengths. Once exposed to hydrocar-bons, the rubber element swells to form an effective annular seal through an ab-sorption process known as thermody-namic absorption (Fig. 1).

The swellable-packer/cable sys-tem is an annular-isolation cable-feed-through packer for both openhole and cased-hole completions that improves on the conventional approach to run-ning feed-through lines through comple-tion packers by completely eliminating the requirement to cut, strip, and splice

in control and communication lines for the feed-through process. Instead, the swellable-packer/cable system is manu-factured with custom molded grooves through the element to fit the control lines that will be run through it. A slit is then cut in the element down to the depth of the groove so that it can be ac-cessed during the wellsite installation. An engineered running tool is used at the wellsite during installation, and the control lines are fed continuously into the element by the tool as the packer is run through the rotary. The self-healing properties of the swellable-packer rub-ber ensure sealing around the control lines and against the casing as the packer swells and seals downhole. This enables the passage of individual control lines, flatpacks for downhole monitoring, and control devices through the packer.

TestingStage 1: Small-Scale Swelling-Speed Testing. A standardized test sample, 2.875 in.×4.2 in.×0.1 m, with two lay-ers of Type A delay barrier representing the packer, was tested at well conditions

(65°C crude oil) to verify swelling speed (Fig. 2). The test showed that the time to first seal for the packer in a 6.16-in. hole would be approximately 24 days. A 3.5×5.78-in. SP OS packer was found to reach 6.16 in. in approximately 24 days at 65°C.

Stage 2: Full-Scale Differential- Pressure (DP) Testing. A full-scale test packer on 3½-in. base pipe with an outside dia-meter (OD) of 5.78 in. and an element that is 2 m in length with two 23×12-mm flatpacks and one 11×11-mm control-line feed through (Fig. 3) was tested for DP capacity in a 6.16-in.-inside diameter (ID) test unit. The temperature was set to 100°C to speed up the process. After 4 days, the testing personnel noted that the swellable packer had started to seal the 6.16-in.-ID test unit, as DP over the rubber element was observed. After 7 days, the swellable packer held the re-quired 70 bar of DP, and Statoil agreed to continue testing until failure of the rubber element occurred. After 21 days, the packer sustained a stable 202-bar DP. The SP OS L was subjected to a maxi-mum DP of 231 bar, at which point the el-ement failed.

ResultsStage 1: Small-Scale Swelling-Speed Testing. The standardized Stage 1 test sample was prepared with L 2A design (swelling delay as designed in the com-puter software program used to predict swelling) before inserting it into the test unit filled with well fluid. Temperature

Fig. 2—Test sample (2.875-in.×4.2-in.×0.1 m) and test units for swelling-speed testing.

Fig. 3—SP OS L (3.5-in.×5.78-in.×2 m) before test start.

CM160060.indd 138 8/13/13 3:18 PM


was held constant at 65°C for the entire test period. The test was run with an au-tomatic display sensor and was moni-tored continuously.

The swell test showed that the 3.5-in.×5.78-in.-OD packer with L 2A design sealed the 6.16-in. hole within 24 days. The simulation provided a sealing time frame of 19 days. The test results and simulations were quite close up to approximately 6 days. After 6 days, the test sample swelled at a slower rate than the simulation had anticipated. The de-viation between simulated and test re-sults is caused by a test effect, volume dependence, often seen when testing in crude oil. The results are similar when the crude oil is fresh, but, in time, swell-ing will slow down as the rubber takes up the lightest and fastest- swelling C- components first. In a well, where there are unlimited volumes available, a slow-down in swelling speed such as that seen in the test will not occur. Therefore, the swell test verifies simulated swell-ing speed for the first 5 days, and the simulated curve should be used to derive long-term swelling speed.

The actual test results were signifi-cantly slower than the simulations after 5–6 days, which indicates that the lighter components of the crude oil were used, and that the test sample started swelling more quickly when the heavier compo-nents in the crude became available. This effect will not occur in a real well situa-tion, where the swellable packer will have a near-infinite amount of crude available.

Stage 2: Full-Scale DP Testing. After the initial swell-speed test, a full-scale test was prepared to show that the swellable pack-er had the capacity to seal at the 70-bar DP required. To speed up the testing, there was no delay barrier placed on the rubber element, and the test temperature was set to 100°C. Testing showed that the packer held 202 bar, which is approximately three times the required pressure. The test re-sult was 28% higher than the simulated capacity of 157 bar for this design.

With elevated temperature and no delay barrier, the packer started to seal against the 6.16-in. test unit within 4 days. The 70-bar DP was reached within 8 days. After approximately 21 days, the

packer held a DP of 202 bar. Maximum pressure observed before breaking the element was 231 bar.

Case-History Installation The operation in the Troll field was per-formed from a semisubmersible rig with-out the occurrence of any health, safety, or environmental incidents. An average drilling rate of penetration of 288 m/d was achieved while drilling the 4440-m, 9½-in. reservoir section. Drilling and completion were completed by 9 Sep-tember 2011, and the complete job was performed within 32 days (8 days ahead of schedule).

The entire swellable-packer instal-lation, involving feed through of contin-uous control lines and cables, took only 45 minutes per packer. For comparative purposes, standard hydraulic-set packers requiring splicing and testing above and below the packer will normally require at least 12 hours per packer.

All downhole valves and gauges are functioning properly. Zonal isolation has been confirmed by selective closure of the flow-control valves. JPT

CM160060.indd 139 8/13/13 7:18 AM


Dynamic underbalanced (DUB) perforating is a process that

creates a negative pressure differential, or underbalance, causing fluid to move toward the wellbore even in an initial overbalanced static condition. A DUB condition can be controlled by understanding and carefully managing the temporal pressure transients by use of multiple methods within the wellbore during and after gun-system detonation. Recently, a series of instrumented perforation experiments demonstrated that existing cleanup models do not accurately predict perforation cleanup when perforating in a DUB condition.

IntroductionUnderbalanced perforating methods have been applied successfully since the 1950s, shooting both wireline and tubing- conveyed perforating guns. As shaped-charge jet-perforator systems became more advanced, using powdered metal lin-ers, performance steadily improved. The art of minimizing the compacted and dam-aged area surrounding the perforation tunnel, commonly known as the crushed zone (Fig. 1), began shortly afterward. Much of the initial work involved shoot-ing charges into prepared Berea sandstone cores while documenting the effect of a differential pressure toward the wellbore upon perforation efficiencies. As the ben-efits of an underbalanced pressure dif-ferential were observed, extensive testing established criteria for flow volumes and differential pressures required to remove or minimize the crushed zone created dur-

ing the perforating event. Specifically doc-umented was the role of trapped atmo-spheric pressure inside a perforating gun surrounding the shaped charge and com-ponents, known as free gun volume (FGV), which enabled the formation pressure to act as a differential and expel charge and crushed formation into the gun.

As perforating research and field ob-servations continued, a series of wide-ly used and accepted formulas was es-tablished to document the magnitude of differential pressure required to ensure cleaned perforation tunnels. This paper reviews the effectiveness of each of these models, originally developed for a static underbalanced condition before perforat-ing, to predict cleaning and removal of the crushed zone in a series of tests with a dy-namic pressure differential. The test series uses an advanced perforation-flow labora-

tory to detonate an 11.1-g deep- penetrating shaped charge. Each charge will perforate a 24-in.-long, 7-in.-diameter Berea sand-stone core with 3,950-psi applied pore pressure; 9,950-psi simulated overburden stress; and 4,900-psi wellbore pressure, creating a static 950-psi overbalance. Al-though the initial static condition will be overbalanced, a DUB condition will be es-tablished by wellbore and pore fluids fill-ing the FGV upon detonation.

Testing ApparatusThe testing apparatus used to simulate downhole perforating conditions for this work is an advanced perforation-flow laboratory at the Jet Research Center, which is modeled after an API 19B Sec-tion IV test-vessel apparatus (Fig. 2). The test setup uses a simulated gun module that contains a single shaped charge, a detonating cord, and a sufficient amount of FGV that can be regulated relative to the actual gun system being evaluat-ed. FGV for an API 19B Section II or IV test can be calculated by determining the total system FGV and dividing by the total number of charges, thus providing the FGV on a per-charge basis. The FGV

Evaluation of Established Cleanup Models in Dynamic Underbalanced Perforating


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 159413, “Evaluation of Established Perforation-Cleanup Models in Dynamic Underbalanced Perforating,” by Dennis Haggerty, G.G. Craddock, and Clinton C. Quattlebaum, SPE, Halliburton, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8–10 October. The paper has not been peer reviewed.

Fig. 1—Perforation crushed zone surrounding the open perforation.

Charge and Core Debris

Pulverization Zone

Grain-Fracturing Zone

Compacted ZoneWith Damaged PermeabilityFrom Perforating, kc

UndamagedPermeability, k

DamagedPermeability, FromDrilling, Production,or Injection, kd

Cement

Casing

Open Perforation

CM159413.indd 140 8/13/13 7:18 AM


can be increased to simulate the down-loading of a gun system, the incorpo-ration of surge chambers, or a variety of other methods. The gun module is set inside a simulated wellbore volume. After detonation, the shaped charge pen-etrates the gun module simulating the gun scallop; crosses a defined clearance between the gun and casing wall through the pressurized wellbore fluid; and then penetrates the casing wall, cement, and finally the pressurized target rock.

The FGV within the simulated gun module can be modified by using inert material, such as shatter-resistant steel bearings. These can be placed inside the void space around the shaped charge to match the specific FGV relative to the sys-tem used downhole.

Rock cores used are dried to con-stant mass at 200°F and then vacuum saturated in odorless mineral spirits, en-abling the gravimetric porosity value to be calculated. Each core is then mounted in the pressure vessel in which the over-burden pressure is applied, and steady-state flow through the core is achieved to determine permeability.

High-speed pressure sensors, capa-ble of sampling at 115,000 data points per second, are attached to the simulated wellbore to measure the wellbore pres-sure response during and immediately after detonation. The result is a profile of the transient pressure in the wellbore during the perforating event, capturing the inherent or engineered DUB condi-tion if created.

Laboratory TestingAn extensive testing program was con-ducted to evaluate the effect of FGV on creating a DUB condition and the clean-

up of perforation tunnels. Observations were made to determine whether estab-lished models for static underbalance could predict perforation cleanup when only a DUB condition is achieved. Fig. 3 presents a comparison of two test shots from the series, each with different FGV. As expected, the greater FGV created a larger DUB condition. Core 09 was per-forated using 241 cm3 of FGV, creating a maximum dynamic underbalance of 2,280 psi, which resulted in only 3.30 in. of open perforation tunnel or 38% of total-core penetration. Core 11 was per-forated using 905 cm3 of FGV, creat-ing a maximum dynamic underbalance of 2,590 psi, which resulted in 8.10 in. of open perforation tunnel or 100% of total-core penetration. Immediately after the perforation tunnel is created, the sur-rounding wellbore fluids enter the per-foration tunnel in an attempt to equalize the wellbore and pore pressures (over-balanced condition). However, the well-bore pressure decreases beyond the pore pressure, thus establishing an underbal-anced pressure differential where one did not exist initially—a classic example of the DUB condition.

Although Cores 09 and 11 were ex-posed to an underbalanced pressure greater than the minimum required by the presented models to achieve a clean perforation tunnel, only Core 11 was cleaned sufficiently. Core 09 was ex-posed to a 2,280-psi underbalance and was cleaned only partially. Fig. 5 in the complete paper shows that the maximum underbalance for Core 09 lasted for a much shorter period of time than that for Core 11, suggesting that there is a time dependence to achieve cleanup not con-sidered in the models evaluated. The re-

sulting DUB effect is related directly to the amount of the FGV increase in the simulated perforating gun in the experi-mental data.

DiscussionIn a perforation event, a charge punches a hole from the gun into water, through casing, then into rock. This action is fol-lowed by a bubble of explosive mixed with water, air, and other materials gath-ered along the way. The charge creates a perforation tunnel filled mostly with ex-plosive gas. This gas, along with the liner, compresses the material on the tunnel boundary. Because the pressure in the perforation cavity is high, flow does not occur until the gas relaxes in pressure. Gun volume plays a role in the relaxation. The bubble then escapes the tunnel. This gas rush precedes any underbalance ef-fects and will begin the underbalance process as soon as the gas pressure is below the pore pressure. Because the gun is already at high explosive pressure, the bubble of explosive gases will flow into the region between casing and gun or into the gun if the pressure is relaxed quickly enough. As the cavity clears, the pressure underbalance forces pore fluid to migrate rapidly to the wellbore. The first region to experience the effects of the low-pressure wellbore fluid is near the perforation-tunnel entrance.

Removal comes from two mecha-nisms. The first involves the flow through

Fig. 2—The Jet Research Center perforation-testing apparatus.

Fig. 3—Perforated cores using different FGVs, resulting in different amounts of open perforation tunnel. Low-melting-point-temperature eutectic fills the “open” portion of the perforation tunnel.

Gun Volume/Surge Chamber

Simulated Formation

Simulated Wellbore

Core 09 Core 11

CM159413.indd 142 8/13/13 7:18 AM


the crushed zone that then entrains and removes lower-porosity particles. The second mechanism entails the tip erod-ing away and then flow along the cavity erodes material off the walls. These two mechanisms can occur at the same time. The tip effect would benefit from a rough cavity wall. The uniform case is less sen-sitive to the rough cavity wall, but the uniform case is more sensitive to par-ticle size in the crushed zone. The first region to experience the underbalance is near the tunnel entrance; consequently, cleanup can, in principle, occur at both ends of the cavity: at the throat as a re-sult of an early start and at the tip as a re-sult of the weaker crushed zone.

Previous work has focused on solv-ing the pressure equation and then popu-lating a flow equation, such as the Darcy equation. A rock-strength threshold was used. First, the layer crushed-zone thickness is estimated for an 11.1-g deep- penetrating charge by shooting into a standard quality control setup with dry sand as the target. The result showed a high-density region around the tunnel cavity of 0.2 to 0.5 cm. This result corre-lated with physical measurements made

of the perforated cores. A thin layer of material is assumed along the conical structure. A slab model is initially as-sumed, but the model can be extended to a cylinder if necessary. Next, it is as-sumed that the flow moves a boundary of material, which in turn alters the pres-sure gradient.

As the flow increases, instabilities break up the flow; these instabilities transition to eddies, which in turn tran-sition to smaller eddies. This is the so-called cascade to smaller scales. Using a tensile strength of 600 psi, the clean-up occurs quickly, starting at flows of 200 cm/s. The crushed zone is sepa-rated from the tunnel wall in approx-imately 300 microseconds, and the flow pushes the now-free material out of the perforation cavity in roughly a few milliseconds.

Now, consider the case of the tip. In this case, the tip of the perforation tun-nel has the lowest tensile strength. The flow then can predominate along the length of the perforation tunnel. This flow would clear the crushed material by friction at the surface. This is a less-effi-cient mechanism than pushing through

the crushed material. For smooth-pipe flow, the surface friction coefficient is from the Blasius equation. The tip mode of perforation operation begins with a jet model. A jet will have an angle (from centerline) of approximately 12.5°. In-side the cone, the flow is fast. Outside 12.5°, flow significantly decreases. Thus, to optimize cleanup with this model, the tip of the perforation cavity should have a shallow angle.

Conclusions1. The greater the FGV of a

perforating system, the greater the DUB condition achieved.

2. FGV is a natural occurrence in any perforating-gun system and can be optimized to increase DUB.

3. Established underbalance models presented in this work do not appear to accurately predict perforation cleanup on the basis of laboratory results.

4. Proposed models linking fluid velocity to perforation cleanup seem reasonable, but need further study. JPT

CM159413.indd 144 8/13/13 7:18 AM


J.C. Cunha, SPE, is drilling manager for Ecopetrol America in Houston. Previously, he was the well-operations manager for

Petrobras America. A former associate professor of petroleum engineering at the University of Alberta, Canada, Cunha has served on several SPE committees and is currently chairman of the SPE Technical Communities Coordinating Committee. He holds a civil engineering degree from Juiz de Fora Federal University, Brazil; an MS degree from Ouro Preto University, Brazil; and a PhD degree from The University of Tulsa, the latter two in petroleum engineering. Cunha has authored many technical articles, including more than 30 SPE papers, and has coauthored two recently published SPE books, Advanced Drilling and Well Technology and Fundamentals of Drilling Engineering. He was a 2010–11 SPE Distinguished Lecturer.

Recently, while preparing to present a seminar on deepwater-well-construction opti-mization, I tried hard to find a word or a phrase that could be seen as “the secret” for a safe and optimized drilling performance—something very simple that would summarize what must be done to achieve success in an activity that, besides being the most visible face of the oil industry, is also simultaneously the most vulnerable and criticized.

What I was trying to do was encapsulate what is a very complex task, the success-ful management of drilling operations, in just a few words. This proved to be a futile exercise. After many hours of trying, I ended up not succeeding in obtaining my catch-phrase. On the other hand, that helped me a lot in obtaining the main message for the seminar. There are no quick fixes. The management of a large group of people oper-ating very sophisticated equipment, under restricted conditions, and within a limited space is a mission filled with complexity. But it is our mission, and we should strive not only to succeed but also to improve our performance constantly. As I mentioned in my last article, a flawless operation is a result not only of good management but also of careful planning.

In the seminar, I ended up concentrating on a few points—before, during, and after the operation—that should be viewed as fundamental for the success of the job. In the planning phase, make sure that you are aware of all details involved in the oper-ation and what the risks and possible contingencies are. Then, while executing the operation, be aware of all developments. Use your real-time data as an efficient tool to verify what is going well and what needs to be corrected and to predict what is com-ing. Finally, after concluding the operation, make sure to capture the lessons learned. This is at least as important as the planning process.

To emphasize the importance of using lessons learned, I would like to conclude with one of my favorite quotes, attributed to Peter Drucker, widely viewed as the inventor of modern management: “A manager is responsible for the application and performance of knowledge.” JPT

TECHNOLOGY

drilling management and automation


SPE 163302 Intelligent Real-Time Drilling-Operations Classification Using Trend Analysis of Drilling-Rig Sensors by A. Arnaout, TDE Thonhauser Data Engineering, et al.

SPE/IADC 163510 Advanced Dynamic Training Simulator for Drilling and Related Experience From Training of Drilling Teams With Focus on Realistic Downhole Feedback by Sven Inge Ødegård, eDrilling Solutions, et al.

SPE 163489 Operational Control and Managing Change: The Integration of Nontechnical Skills With Workplace Procedures by J.L. Thorogood, Drilling Global Consultant LLP, et al.

SPE/IADC 163515 Advances in Real-Time Event Detection While Drilling by R. Wong, Schlumberger, et al.

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Data-mining processes are fundamental in obtaining

the predictive benefits of real-time systems and have been progressing from descriptive to predictive optimization methods. These methods are enhanced by real-time and historic data. Advanced sensor technologies, improved data-quality control, wellsite information-transfer standard-markup-language (WITSML) data advantages, and virtual real-time drilling-optimization concepts have been assimilated into the design and implementation of prediction systems.

IntroductionAs technologies evolve and the WITSML standard allows data exploitation by many specialized applications, more-accurate and reliable drilling data are available at real-time operation centers (RTOCs) to analyze and mitigate drilling issues. This enhances and speeds up the drilling-optimization process, and allows a small group of highly skilled drilling en-gineers to support several wellbore con-structions simultaneously.

However, the traditional tasks of monitoring drilling parameters are still constrained by the constant need for human intervention. First, the particu-lar field-operations knowledge gained by RTOC monitoring engineers is very valu-able but fragile, because it requires the continued participation of team mem-bers. To ensure that nothing is over-looked, that knowledge should be gath-ered and used by an intelligent system.

Second, the status of a particular event or well is constantly changing as key drill-ing factors change, and monitoring en-gineers must review all data in detail be-fore manually defining the new status of a system. Third, a complete update of a general well-operations status report is time consuming. The operations status for a set of wells being drilled and moni-tored can change dramatically from one minute to the next and therefore requires the constant participation of an engineer. Such a report should be automated to de-rive maximum benefit from the best real-time and historic data.

Drilling-Data MiningThe drilling industry is aware of the im-portance of pattern analysis and past performance of correlation wells. It has looked to similar drilling-well experienc-es to predict the probability of a particu-lar event or drilling outcome. This has been achieved effectively with human in-tervention, despite the fact that multiple data families that needed to be taken into account were difficult to access for differ-ent reasons.

As well complexity has increased, computer data-processing technolo-gies, telemetry instrumentation, and real-time data-acquisition systems have advanced, providing the ability to use computer power to choose and examine an increasing volume of more- complex data. This has enabled discovery of pre-viously undetected drilling patterns from correlation wells and known po-tential events from ongoing drilling programs, making real-time data expo-

nentially more meaningful and more ef-ficient for monitoring purposes. Because real-time data are properly related to drilling-program and well-correlation data, it is possible to develop models for predicting future outcomes through new software systems that automatically re-late, set apart, and announce a potential drilling challenge.

Application of the Traffic-Light MethodologyTo reduce the time engineers invest de-ciding where to focus their attention on conventional real-time consoles, the event or well status is defined by intuitive colors used on the system interface. They are predefined as green for stable, or on the program; yellow for alert, or near the limits of the program; and red for critical, or outside of the program. This applies to a particular drilling aspect and to a gen-eral drilling-operations dashboard able to reflect the status of several wells being drilled concurrently.

The criterion and color definition are automatically applied by the system as new real-time values, and trends are constantly renewed and compared with relevant historic information. The status can be modified manually by the moni-toring engineers if necessary.

More-Accurate AlertsTraditionally, alerts have been prepared by monitoring engineers at RTOCs. How-ever, most of them were triggered by en-gineers’ data visualization or alarms dis-played by the real-time systems. This is inefficient, because it demands signifi-cant time from monitoring engineers to validate the accuracy of the alarm before an alert is posted.

Therefore, alarms in the computer- driven system were automated under the premise that all should be as accurate and important as the data make possi-ble. Hence, algorithms were developed

Design of an Automated Drilling-Prediction System


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163709, “Design of an Automated Drilling-Prediction System—Strengthening-While-Drilling Decision Making,” by Samuel R. Pérez Bardasz, SPE, Edwin David Hernández Alejadre, and Armando Almeida León, Petrolink, prepared for the 2013 SPE Digital Energy Conference and Exhibition, The Woodlands, Texas, USA, 5–7 March. The paper has not been peer reviewed.

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specifically to assess a limited set of the most recent data points for tempo-ral trends, and to compare them with those expected on the basis of the drill-ing program and correlation wells from the WITSML database. This reduces the number of false alarm emissions com-ing from data-point outliers that some-times are part of a log curve or from a data-transmission failure (such as noise). Algorithms have been intentionally de-signed to avoid system alarms being trig-gered if the transmission system is miss-ing family data at a certain time or depth interval, if one value is outside of the pro-gram range, or if a block of received data is outside of the range at a depth or time where it is expected to be that way.

Alarms are triggered taking into ac-count two data sources (real-time stream and historic database). Thus, alerts rep-resent warnings derived not only from surface potential issues or imminent downhole threats being identified in real time, but also from potential wellbore is-sues identified through correlation wells or as predefined in the drilling program.

Because this process requires data to be compared by a unique computer application, the drilling-data standard WITSML was put in place, as well as a sys-tem of measurements for downhole and surface parameters—the set of units that operators use. Similarly, new features re-lated to the fluids data displayed were de-veloped for the pre-existing application. All drilling-program data must be avail-able in a standardized format to be up-loaded to the system.

More-accurate automated alarms maximize the decision value of the alerts that are finally prepared by the monitor-ing engineers.

Anticipating Events and Trouble ZonesThe design of an automated drilling- prediction system was started by cover-ing drill-bit performance, fluid changes, and varying rock formations. These three points have data in the form of a program as well as in real time.

Drilling performance has a direct relation to drill-bit efficiency. Therefore, drill-bit information is used to moni-tor the well, taking into account start/end depth; casing-stage diameter; ini-tial/final weight on bit; minimum/maxi-

mum revolutions per minute; minimum/maximum rate of penetration (ROP); and minimum/maximum pump pres-sure, flow rate, torque, type, diameter, and total flow area. These parameters are filtered, related into a database, and displayed on a console. If a real-time value is outside of the range defined by the program, the system will send au-dible and visible alarms. This is com-plemented and supported by a depth-based plot on which real-time data of ROP, resistivity, and gamma ray are visibly compared.

This information is complement-ed with downhole-drilling- equipment features if available, either from a conventional-motor or a rotary- steerable system. The data taken into account are maximum tool temperature, hours of motor life, and motor brand and model. An indicator of formation temperature vs. motor temperature completes the in-formation immediately available to the monitoring engineer before an alert is posted.

Drilling-fluids aspects taken into account include program values for density, plastic viscosity, yield point, salinity, water/oil fraction, filtration, emulsion stability, equivalent circulat-ing density, loss, and gasification. All program values are uploaded to the sys-tem, where specific algorithms are ap-plied to compare them with real-time and near- real-time fluid data. This results in a display that quickly shows which pa-rameter requires attention; each has a traffic-light indication.

Rock-formation and lithology- column information can be compared using the real-time data stream and static data stored in the system. Data available from correlation wells and from the drill-ing program are matched with logging-while-drilling data and near-real-time lithology data, if available. The era, for-mation, and lithology description are re-lated to measured depth below the rotary table, to true vertical depth below mean sea level, and to measured depth and measured bed thicknesses. Once these static data are related with the real-time data, a traffic light is displayed on the console, indicating at least whether, for a specific measured depth, the rock era, formation, and lithology match those in the program.

This console is complemented with a depth-based well-correlation panel that provides gamma-ray, resistivity, and lithology-column information that en-hances the decision-making process to trigger an alert.

Adding a degree of importance to each one of the described-in-detail in-formation tracks, it is possible to de-fine a general-parameter status by use of complex algorithms, resulting in a traffic-light expression. Each data fam-ily is used as a macro or rule that speci-fies how a certain input sequence should be mapped to a replacement input se-quence, and how much impact it should have on the general well status. It is important to mention that other fam-ily data such as trajectory or cementing data can be taken into account for the anticipation of drilling issues and fast, accurate alert generation.

Thereafter, two other well-status screens enter the process: one that takes into account the set of events such as kicks, total loss, and friction and torque issues that occurred on the correla-tion wells; and one that takes into ac-count the current well-operation status. These provide easy-to-read key informa-tion to the monitoring engineer, who is now able to focus more on data-trend analysis than on data validation and data-trend identification. It is impor-tant to mention that the automated sta-tus can be edited manually by the mon-itoring engineers if the status shown is not what the operator or the rigsite staff confirms.

General RTOC DashboardIronically, RTOC status reports are not commonly available in real time. In-stead, this task is performed from time to time, depending on the operator com-pany’s interests, because it demands full attention of monitoring engineers for significant periods of time. All real-time plots must be reviewed by the monitor-ing engineers around a specific time, looking for deviation from the plan as trends change for the wells being moni-tored at the RTOC. Combining the three main statuses of all wells monitored at the RTOC into a unique automated dash-board makes the status-report update an efficient task requiring almost no human intervention. JPT

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By 2010, all applicable drilling solutions had seemingly been

applied to the Castilla field in Colombia. But new problems were identified, and a model of management strategies was implemented to reduce drilling and completion timing. During the resulting optimization process, the Castilla field became the model for the rest of the fields in the company portfolio. It is believed that this model might also be applied successfully to other fields.

IntroductionIn a May 2010 evaluation, several facets of Castilla field operations were assessed: current processes, operations, and tech-nologies; the state of drilling operations by use of management indicators; non-productive time (NPT); field character-istics; and roles and responsibilities of personnel. The objectives were to prior-itize processes by importance, create a process guide, develop a new manpower plan, improve communication, and apply technology efficiently.

Optimization Evaluation ResultsField Characteristics. The Castilla field is 200 km from Bogotá in the Lla-nos basin. This field has three forma-tions of heavy oil (T2, K1, and K2) to 7,500, 8,000, and 8,500 ft in true ver-tical depth (TVD), respectively. Most of the wells are drilled to approximately 9,500 ft in measured depth. The major-ity of the wells are J-shaped, with inclina-tions from 30 to 70°. The most common

operational problems in the field were to be found at approximately 1,000-ft TVD, at the shale formation found immediate-ly above pay zones.

Optimization Model. The optimization process had three principal stages: im-plementation, consolidation, and opti-mization excellence. The development of each well had involved five steps dur-ing the drilling process: planning, im-plementation, control, feedback, and optimization. The drilling engineer had to plan the well; implement, explain, and communicate the plan; control the drilling while continuously monitor-ing parameters, ensuring compliance with the plan and the application of the lessons learned; catalog the lessons learned; and apply these lessons to new optimization plans.

The working optimization model was designed around several major strategies, all developed on the basis of technical limits related to health, safe-ty, and environment (HSE): continuous monitoring of indicators; establishment of only one line of communication; ap-plication of short-, medium-, and long-term well vision; and organization based on engineering.

During the measurement phase, new indicators and methodologies, such as the Boston Consulting Group matrix for NPT classification by severity and fre-quency, were included. These method-ologies were not only part of the initial stage of the process, but over time they also became tools for control and moni-toring of trends. The initial evaluation

was focused on four main areas: man-agement indicators, time to optimize, human resources, and oilfield charac-teristics. The Boston matrix was used to identify the severity and frequency of NPT. Several technical and operational tools were used to identify characteris-tics of the oil field, including maps of Cas-tilla losses of drilling fluid and inflows of northern and southern areas; geological maps to identify formation-top depths, faults, dipping layers, and drainage areas of wells drilled; and existing geomechan-ical analyses.

Evaluation Results. A centralized type of drilling engineering management was developed in which well engineering was applied from a central unit that served several fields at the same time. Perhaps this strategy might have worked in a sta-ble operation, but with the high opera-tional activity that Ecopetrol was carry-ing out (and taking into consideration that its goal for production growth for 2010 was 12% over the previous year), it was impossible for this strategy to work. Growth was experienced in all business areas: exploration, production, oil ex-ports, and proven reserves.

The drilling program was a docu-ment of almost 100 pages. Too much time was needed to read it, and still it of-fered little operational detail. As for roles and responsibilities, it was noted that drilling engineers, directly responsible for the drilling operation, were spend-ing most of their work time on receiv-ing calls and only a small portion of their work time on engineering tasks such as planning and monitoring the well, result-ing in important decisions being made hastily by staff not seasoned in the Cas-tilla field. Furthermore, service compa-nies were making changes to engineer-ing procedures or proposals without the input of Ecopetrol. Because of this post-event methodology, the field lead-

Management Strategies Optimize Drilling and Completion Operations


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165325, “A Successful Optimization Case of Drilling and Completion Operations Through Management Tools and Strategies,” by Oscar R. Silva, Guden O. Silva, and Luis I. Valderrama, Ecopetrol, prepared for the 2013 SPE Western Regional and AAPG Pacific Section Meeting and Joint Technical Conference, Monterey, California, USA, 19–25 April. The paper has not been peer reviewed.

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er was spending much of his time solv-ing NPT problems. In addition, the direct responsibility for HSE issues had been handled by one person not working di-rectly for Ecopetrol. Thus, there was no strict monitoring of HSE issues. Finally, a number of specific drilling problems were identified, ranging from adminis-trative (poor management of permits) to technical (unnecessary wiper trips and cementation) concerns.

Engineering-Based Organizational Strategy Although the drilling leader hired new staff for the optimization process, the same organizational structure was re-tained in the rigs. However, the leader used an engineering-based strategy to reorganize the roles and responsibilities of all positions (Fig. 1). The most impor-tant change took place in the operations engineer position of each rig. This posi-tion was retitled drilling engineer and became a planning position, directly re-sponsible for planning, monitoring, and operations of the well. Some duties of the operations engineer, including the logistics of tools and personnel, were delegated to assistant engineers.

The Ecopetrol representative in charge of drilling operations in the field kept his normal duties, but was expect-

ed to adhere to the plan previously es-tablished by drilling engineers. If they wanted to change the plan, they were required to call the operations center in Bogotá and provide an engineering-based justification of their request.

Each service company must submit its engineering products in advance for review by the drilling engineer. Seven op-timization engineers were hired, dedi-cated to supporting specific tasks such as monitoring NPT, managing maps of wiper trips and fluid loss, updating oper-ations, implementing new technologies, and performing several other activities aimed at optimizing the operation.

Single-Communication-Line StrategyMany of the observed problems were caused by a lack of specific responsibil-ity. To ensure communication process-es, tools were implemented by use of all existing channels. Written communi-cation was key, but it would be supple-mented by audiovisual communication and teleconferencing.

The wasteful and unproductive drill-ing program was replaced by an easy-to-read document with strong engineering content. In fewer than 20 pages, the main well data were summarized. The drilling-well-on-paper scheme ensured the detail

of each operation, its parameters, time limits, and lessons learned. This docu-ment was not made at the whim of site leaders but instead was an important feat achieved with the participation of all in-volved in the operation.

A regular video meeting was estab-lished in which the Bogotá offices were in conference with the personnel of six drilling rigs. At 4 p.m., every rig delivered a report. A complete communications room was implemented in the Bogotá of-fices. Cameras were installed in the Bo-gotá communications room and all rig of-fices to facilitate these meetings.

Each service company maintains personnel within the same field, but it is not necessary for these staff members to remain in the same drilling rig. New staff could not handle operations unless they met adaptability and recognition guidelines to stay in the field. Thus, the dynamics of drilling, created over sev-eral months, could be guaranteed, and the lessons learned during this time were not lost.

This process notably improved the working environment. Personnel confi-dence increased, and interdependence was strengthened.

Vision Strategy for the Short, Medium, and Long TermWhen the Castilla optimization imple-mentation began in 2010, many of the targeted problems had their causes in well planning, including construction of negative and nudge sections, problems of collision between wells, very short or very long vertical sections for the angle of arrival at the target, sudden changes in the angle of arrival at the target, land-purchase issues for the cluster, prob-lems with union strikes in certain sec-tors of the field, and flooding problems in the field.

A goal was therefore set for a single well in advance (short term), a cluster in advance (medium term), and well cam-paigns in advance (long term) as fun-damental parts of the optimization be-tween 2013 and 2016. By planning far in advance, the planning of the next well begins when starting to drill the cur-rent well. This allowed a reasonable time to apply lessons learned and op-erational practices, and to adjust for-

Fig. 1—Information-flow model for improvement performance.

Planning and Lessons Learned

Lessons Learned and Feedback

Well Field Operations

Ecopetrol Rep (Night)Rig Superintendents (Day)

Drilling Engineer and Leaders

Planning and OptimizationEngineer

No Drilling SurprisesNPT ReductionHSE PlanningRisk ManagementTechnologyContract ManagementCompletion PlanningCost Management

Office Operations Field Operations

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mation tops, directional profiles, and bottomhole assemblies.

Likewise, when drilling began on the first well of a cluster, the next cluster was planned, which involved purchas-ing land, setting targets to optimize di-rectional plans, monitoring civil works for locations, acquiring permits from the government (which required a minimum of 30 days from the filing of documents),

and engaging in socially conscious in-teraction with the community, among other tasks.

ResultsThe total drilling and completion time of the Castilla field for 2010 was reduced by 35%, from an average of 29 days to 19 days. The days/1,000 ft indicator was decreased from 4.2 to 1.9. Completion

times were reduced by 40%, from an average of 6.7 days to 3.7 days. The cost savings was greater than USD 50 mil-lion for the campaign. The level of com-mitment, awareness, and knowledge in HSE rose at all levels. The frequency of HSE incidents did not rise despite the man-hours in field operation increasing by 50%. JPT

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The central Luconia gas province located offshore Sarawak houses

numerous carbonate reservoirs (Fig. 1). Some of these reservoirs are characterized by the presence of karsts and fractures, contributing to total mud losses. Implementing the variant of managed-pressure-drilling technology called pressurized mud-cap drilling (PMCD) allowed targeted total depths (TDs) to be reached on several wells. However, reaching TD alone is insufficient for conclusive evaluation. Integration of technology applications is paramount in increasing the success rate of data delivery.

IntroductionWell-known for highly varying forma-tion properties even within small sec-tions of reservoir, the recently discovered Malaysian carbonate formations pres-ent a risk of drilling-fluid losses. Con-ventionally, these wells were drilled with overbalanced mud and losses were cured with lost-circulation materials (LCMs) or cement plugs to enable restoration of overbalanced condition for future drill-ing. Drilling a multiple total-losses zone conventionally proved to be highly un-economical and likely to jeopardize the safety of the operation. To mitigate this inefficiency and associated safety risks, the PMCD technique was implemented and made ready for all of the opera-tor’s carbonate drilling operations. Since 2010, PMCD equipment and personnel

have been mobilized for 11 wells, but have been used only in six wells.

Introduction to PMCD PMCD is applied in the total-loss condi-tion. Once sufficient loss rates are en-countered, the annulus is displaced from overbalanced drill-weight mud to under-balanced light annular mud (LAM). The LAM is generally designed to be under-balanced to the formation pressure at the topmost fracture by approximately 100 psi. This enables gas migration into the wellbore to be monitored closely.

After casing pressure has increased to a limit, LAM is injected into the annu-lus to bullhead the migrated gas back into the formation. Upon each injection, the casing pressure will be restored to the original 100 psi. Drilling operations are performed while injecting seawater continuously down the drillstring and intermittently injecting LAM down the annulus. Drilled cuttings will be carried by seawater and fed into the fractures. Planning for successful PMCD opera-tions not only revolves around equip-ment and engineering, but also depends on well placement and architecture, well engineering, rig equipment, training, and logistics.

Successful PMCD Implementations in the KUN2 Well This well was drilled in August 2012 by use of a semisubmersible drilling rig. Upon drilling 11 m into the carbonate

Integrated-Technology Approach Enables Successful Prospect Evaluations in Malaysia


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164576, “Integrated-Technology Approach To Explore Carbonate Reservoirs in Malaysia Enhances PMCD Potential and Enables Successful Prospect Evaluations,” by M. Noreffendy Jayah, SPE, Intan Azian A. Aziz, SPE, Zulhilmi Drus, SPE, Thanavathy Patma Nesan, Wong Han Sze, SPE, Abdel Aziz Ali Hassan, and Pungut Luntar, Petronas, prepared for the 2013 IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, San Antonio, Texas, USA, 17–18 April. The paper has not been peer reviewed.

Fig. 1—Area of operations.

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section, a total loss of drilling fluids was experienced. Loss rate was record-ed at approximately 1,200 bbl/hr. The well was successfully drilled to TD in PMCD mode. Once at TD, the bottom-hole assembly (BHA) was stripped out and a composite bridge plug (CBP) was run into the hole and set inside the pro-duction casing (i.e., several joints above the shoe). The well was then displaced to kill fluid before the running tool was retrieved to surface. A drill-in liner sys-tem was then run into the hole and used to drill the CBP. The well was converted back to PMCD mode once the CBP was drilled out, and the liner was then run to TD. The well was secured upon setting of the liner-top packer.

Main Challenges The main challenges faced in drilling car-bonate exploration wells include deter-mining the top of the carbonate to enable the correct setting depth for production casing, ensuring efficient PMCD opera-tions, acquiring pore-pressure data, iso-lating the well after drilling to TD in PMCD mode, and determining an opti-mum well-killing method after perform-ing production testing.

Solutions Optimization of Carbonate Prediction With Seismic-While-Drilling (SWD) Technology. To ensure successful PMCD operations, a hole section has to be dedi-cated to the carbonate section. The pres-ence of shale within this section will in-troduce borehole-stability risk once the drilling operation is converted to PMCD. To prevent shale exposure in the PMCD section, determining the correct section depth for the hole section before carbon-ate is of great importance.

To accomplish this goal, SWD was used in the KUN2 well. During SWD runs, vertical seismic profiles were initiated during pipe connection and waveforms were transmitted to the surface during drilling operation. The result can be an-alyzed by the project geologist and geo-physicist on site to produce an updated top-of-carbonate depth prognosis while the hole is being drilled. The accuracy of the prognosis will increase as seis-mic is initiated deeper and closer to the target formations.

Ensuring Efficient PMCD Operations. One of the main challenges in ensur-ing successful and efficient PMCD op-

erations is drilling in one bit run. This will significantly minimize consumption of LAM and eliminate the exposure to well-control risk when the BHA has to be tripped out of hole under a total-loss condition in the middle of the operation. From past experience, the main problem hindering this goal is LWD failure caused by vibration and drill-bit wear. While the latter definitely requires a bit trip, LWD failure during PMCD drilling also mandates a trip out because LWD is the only viable means of obtaining openhole formation evaluation once total losses are encountered.

Acquisition of Pore-Pressure Data in Total-Loss Condition. Because of the inability to perform openhole wireline logging after converting to PMCD mode, the operator deployed a formation-pressure-while-drilling (FPWD) tool in PMCD/total-loss mode. The challenge of obtaining a good pressure point in PMCD mode derives from the absence of mudcake (with seawater being used as drilling fluid) and from the potential ex-istence of fracture lines across the bore-hole wall. In KUN2, borehole imaging while drilling was included in the BHA

Fig. 2—Running sequence for setting and drilling the CBP. RCD=rotating control device; SSBOP=subsea blowout preventer; SAC=sacrificial fluid; RIH=run in hole; POOH=pull out of hole.

RCD

Riser

SSBOP

LAM

9⅝ in.

SACFluid

Drill to TDin PMCD.

Strip out ofhole. Close BOPto handle BHA.

Make up CBP.RIH and set

CBP. Displacekill mud. POOH.

Make up linerand RIH to CBP.

Drill CBP.

Continuerunning

liner to TD.

1 2 3 4 5 6

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to facilitate the selection of a good pres-sure point. Throughout the reservoir section, 25 pressure points were taken, with the majority failing to achieve good seals. When the few valid points were compared with data obtained from the production test, it was found that the measurements from FPWD were incon-sistent with the production-test data. Because there is higher confidence in the reliability of data from production testing, it was concluded that the FPWD data were questionable, which could be attributed to the abnormal and uncon-ventional wellbore conditions observed in PMCD mode.

Because of the challenges involved in obtaining pore-pressure data when the well is converted into PMCD mode, an alternative measurement meth-od is proposed in the KUN2 well using annular-pressure-while- drilling (APWD) measurements. In theory, the use of pressure-while-drilling capability will en-able estimations of pore pressure in the reservoir section in PMCD mode. The idea is to measure equivalent-static- density data from the APWD tool during con-nections, when there is no LAM being pumped into the hole. It is assumed that, when left static for a sufficient time, the fluid in the borehole will gravity segre-gate, with an LAM column fully supported by the pressure at the topmost fracture.

Isolations of Wellbore Against Total Losses. From past experience, repeat-ed attempts to prevent losses with con-centrated LCM pills of up to 120 lbm/bbl

will be unsuccessful, the key reason being the nature of the loss zones them-selves (i.e., cavernous/vugular). Cement plugs were tried but demonstrated a poor success rate, mostly achieving suc-cess only upon the seventh attempt or even later. Because of the failure of these methods, the gunk-plug option was ex-plored. Gunk plugs, in theory, seemed to have ideal characteristics, providing temporary isolation while not plugging the vugs. Though the first pilot test of gunk plugs in early 2012 was largely un-successful, gunk plugs seemed to be a likely solution.

In addition, CBPs were used as an isolation solution. CBPs are made of substantially nonmetallic components, usually composed of a fiber-and-resin mixture such as fiberglass or of high-performance plastics. Because of the na-ture of the composite materials, the CBP is drilled out easily in a single-pass op-eration. After the CBP is set, the well will be displaced to kill fluid to overbalance the pressure below the plug once it has fully flipped to gas. Previously, the op-erator had twice used the CBP success-fully as a temporary isolation method for carbonate wells. In KUN2, the CBP was not set after five attempts. On the last at-tempt, the string was turned and recip-rocated as an attempt to clean the casing wall, which eventually allowed the CBP to be set successfully. (See Fig. 2 for the CBP-running sequence.)

A third solution, a drill-in liner- hanger system, was used in KUN2 in combination with a premium high-

torque gas-tight connection and six-bladed drillshoes. In KUN2, a CBP was drilled with LAM pumped through the drillstring. After approximately 15 min-utes of drilling, a total-loss condition oc-curred as the CBP was drilled through and PMCD mode was activated again. Fluid injection was switched to seawater, and the liner was reamed down to TD. After TD, the liner was set hydraulically. Because of a persistent total-loss state, achieving good cementation was almost impossible. To ensure well integrity for testing, the operator had practiced in-stalling three floats for the liner and a tie-back packer to provide seal redundancy at the liner lap.

Well Killing After Production Testing. This process is a major challenge. Ex-perience has shown that even pumping a massive volume of LCMs will not cure the losses, so it has been agreed that no attempt will be made to cure the losses after a production-test operation. The wellbore will only be isolated from the losses zone with a mechanical device. To date, the operator had implement-ed this strategy successfully in several wells where an expandable bridge plug had been run through the test string and set above the perforation zone. Cement plugs were then set above the bridge plug with several dump bailer runs and allowed to harden before being pres-sure tested. The well was then displaced to kill fluid to allow retrieval of the test-ing string. JPT

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Drilling, completion, production, and general surveillance are all

areas that benefit greatly from remote real-time analysis. However, several challenges to remote services exist, including communications issues, fear of job loss, and working outside one’s comfort zone. What is considered an important development goal for a business might be regarded as a threat to an individual, leading to reduced development within remote services.

Remote-Operations Business ModelA remote-operations business model re-moves geographic location and physical distance in all phases of oilfield-service delivery. It reduces the cost of deliver-ing services, increases geographic reach, and improves safety. Remote operations, in essence, are real-time workflows that integrate personnel at rigsites and at as-sembly and maintenance and overhaul (AMO) facilities; at remote operations centers; or at real-time operational cen-ters (RTOCs) anywhere in the world.

Remote operations are the acquisi-tion of sensor data from rigsite equip-ment and instruments, and the trans-mission and processing of those data from remote locations. Monitoring, alarm, or advisory services are delivered in real time with global delivery models, increasing the capability to move work from the point of service to another lo-

cation, where it can be performed more safely, more quickly, and at a lower cost.

Infrastructure, while critical, is only an enabler. The true sources of effi-ciency and competitive advantage come from the organizational redeployment of the workforce and the re-engineering of workflows. Providing on-demand ex-pertise enables service providers to de-ploy new technology faster and deliver high-end services in areas with few local qualified resources. Customers also ben-efit from bundled services, which re-quire the integration of different dis-ciplines and expertise that may be in short supply.

The Digital Oil Field Improved connectivity through radio link, fiber optics, and satellite systems has opened a new world of opportunities for operation optimization. Real-time op-erations monitoring occurs from any of-fice, accessing data streams through Web portals. New downhole tools and soft-ware have been developed on the basis of these new abilities, and new service lev-els have resulted, leading to new and in-teresting jobs, improved well placement, high service quality, and reduced non-productive time (NPT).

Some of the most important con-tributions to drilling analysis include real-time services as a function of new downhole tool technology, improved te-lemetry, and fast access to near-real-time downhole data; oilfield standardization for data aggregation and transfer (WITS/WITSML/PRODML); and new engineer-ing software.

In the early stages, most real-time monitoring was used only by field per-sonnel. However, as real-time data were displayed in the service-provider

Real-Time Analysis for Remote Operations Centers


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16999, “Remote Real-Time Analysis—A Game Changer for Remote Operations Centers,” by Erland Saeverhagen, Arve Thorsen, Jan Ove Dagestad, Nic Spanovic, and Kate Cannon, SPE, Baker Hughes, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission.

Fig. 1—Restructuring the traditional drilling services by introducing remote centers and changing workflow and processes.

Global /Regional Ops Support

24/7 Ops. Tech SupportLWD & DD Expert Advisory

X-Training

2 X DD

6 xML/SC/Loggers (1 x RPS)

2x MWD

Rig 1 Rig 2

Traditional ManningPersonnel per Rig

Global/Regional Ops Support

24/7 Ops.Tech SupportLWD & DD Expert Advisory

2 xML/MWD2 x DDx

Rig 1 Rig 2

Remote Ops and RemanningPersonnel per Rig

2 x SC/Loggerson Demand

Remote MWD / LWD CrewRemote Dir. Drilling CrewApplications Engineer

OPS Center Remote Ops Team

IO Drilling Engineer

+

DM16999.indd 160 8/13/13 7:34 AM


or oil-company offices, new process-es and services were established and were conducted remotely in newly de-veloped remote operations centers or in both parties’ offices. Field person-nel were remanned, and field job func-tions were integrated through special-ized cross-training programs.

A 24/7 operations cycle was imple-mented for key services in the operations centers; specific field functions that were conducted in front of a PC were physical-ly reallocated from the field to the remote center. The model provided the means of reducing the number of field person-nel significantly [especially for drilling services, where measurement-while- drilling (MWD)/logging-while-drilling (LWD) and surface-logging services could be conducted remotely].

The idea behind the model was to reduce personnel at the rigsite and to transfer the job tasks to a remote opera-tions center. Fig. 1 shows the change in personnel needed in the traditional work model compared with multiple rigs with remote personnel, and the reduction in personnel that need to be transport-ed to any rigsite. The increased support level is also illustrated, and the expertise level within the support organization is also enhanced.

Remote Real-Time AnalysisThe connectivity, real-time data display, and reliable communication flow of fully equipped remote operations centers and RTOCs set the stage for the future of re-mote services. Important areas exist in which oil companies and service provid-

ers can improve their operations signifi-cantly, such as prejob planning and drill-ing execution.

Achieving superior drilling perfor-mance requires more than merely select-ing the appropriate drill bit and bottom-hole assembly (BHA); recommendations often relate to all aspects of the drilling operation. Drill-bit design, BHA setup, and the analysis of borehole geometry vs. formation zones, hole cleaning vs. pres-sure, and fluid and vibration patterns all form the drilling environment.

The drilling-optimization adviser has a wide range of knowledge about drilling practices, but without the correct rock-property analysis, that knowledge is insignificant. Measurements must be ac-curate and timely to ensure that adequate changes are made as necessary. Verify-ing measurements is the first step in au-tomated drilling—the input parameters must be correct.

Remote automated drilling-adviso-ry service, which recognizes potential drilling problems before they occur, is an additional tool for the drilling adviser/ engineer. The adviser/engineer provides their best operational advice on the basis of continual real-time surveillance and interpretation of all available data in ad-dition to the automated decision support from the case-based reasoning software. This integrated solution, built on the premise that similar problems have simi-lar solutions, delivers constant surveil-lance, interpretation, and advice within a collaborative environment to reduce un-certainty, minimize NPT, increase safety, and enhance efficiency.

Case-based reasoning software au-tomatically identifies events and trends. When the system identifies a potential problem, it is brought to the attention of the drilling adviser/engineer. The best course of action is determined and neces-sary personnel are notified with recom-mendations for correction. Fig. 2 depicts the case-based reasoning workflow.

In addition to the remote drilling- advisory services, there are a number of other tasks that can be conducted remotely. In this context, it is impor-tant to mention real-time pressure or equivalent-circulating-density manage-ment, pore-pressure prediction, and wellbore stability as tasks that can be performed continually from a remote op-erations center or clients’ RTOCs. Col-lecting and analyzing borehole cuttings and evaluating possible cavings are tasks that must be performed at the wellsite. Proper use of photography and scales enables the caving evaluation to be per-formed remotely, thus delivering a more advanced scan of the caving.

Real-time data are also extremely important in the planning phase for re-viewing, improving, developing, and fol-lowing up on field-specific best drilling practices. All available data, including real-time drilling-fluid parameters, are used in this type of analysis, predicting situations at any well depth with current parameters. Advice is given to help avoid stuck pipes, lost circulation, and hole col-lapse, and to stay within predetermined operational envelopes.

Continuous operation monitoring is required during tripping in and out, where running speeds are estimated on the basis of analysis of available real-time and historical data. The reaction of ad-justing the mud-weight window up or down is dependent on the mode of fail-ure interpreted from 1D geomechanical analysis. By integrating drilling experi-ences, the geomechanical model can be calibrated, providing an optimized geo-mechanical analysis.

Reservoir navigation is another concern that has moved from the field to remote operations centers without problems. The reservoir- navigation su-pervisor primarily works from the client’s office; reservoir-navigation engineers perform continuous drilling- progress and LWD-log-response analysis, updat-

Fig. 2—Data flow for case-based reasoning.

Data Experience

▲ ▲▲ ▲

KeywordSearch

Knowledge ManagementSystems

Data Communication and Storage(WITSML Server)

Rig RigRig Rig

PhysicalModels

Updated inReal Time

DataAnalysis

andStatistics

Visualizationand

Set-LimitSurveillance

Indexing and ActiveRecall of

Human Experience

HistoricalReal-Time

Data

BestPractices

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OtherDocuments

DM16999.indd 162 8/13/13 7:33 AM


ing the Earth model while drilling. When there are recurring differences between the premodeled expected physical prop-erties of the reservoir and the actual ob-served measurements, the objective is to ensure that changes made are kept to a minimum to maintain consistency with other data.

Prejob modeling is required to pro-vide road maps for what can be expected during section drilling, where real-time data and subsequent analysis dictate the well path to be drilled. Discrepancies be-tween a prejob Earth model and projec-tions being made on the basis of real-time data can immediately halt the drill-ing process; a thorough analysis of the real-time data and the model determines future actions. In some instances, the model is altered, and drilling commenc-es. In other cases, the discrepancy is ac-cepted or leads to sidetracking, and new well profiles must be drilled. The process is labor intensive and requires a clear and streamlined communications plan.

In production, significant achieve-ments have been made in optimizing electrical submersible pumps (ESPs), such as improving pump life cycles and detecting scaling and other problems. Production is controlled remotely from an operations center, where thousands of pumps are monitored and operation sequences are analyzed simultaneously on the basis of real-time data. The auto-matic analytics determine the ESP’s con-dition, and appropriate action is taken. Automatic chemical injection of, for ex-ample, scale inhibitors is also conducted remotely. The automated analytics and alarms provided by the software enable repair and workover field crews to be es-tablished in a controlled atmosphere.

The latest addition to the remote-operations domain is the situational-awareness and operational-visualization system, which triggers specific work-flows to be followed. The system inte-grates data, visual feeds, and audio chan-

nels, providing operations traceability. The system engages all operations par-ticipants, providing a comprehensive view for coordinating actions and re-sponses. It also contains recall and re-play functions of all information sourc-es for after-action review. All acquired data are stored in a black box at the rigsite in case of an unexpected event, and are also displayed in real time in a continuously manned RTOC or opera-tions center. Fig. 3 shows one possible remote- operations-center layout. Visual information from the wellsite is shown through cameras, and sound is transmit-ted through open-communication chan-nels, avoiding phone calls as much as possible. The circle is completed in the operational environment, giving feed-back to the real-time operations crew.

Benefits and ChallengesFor more than a decade, remote opera-tions have been implemented in the oil and gas industry, with significant prog-ress made through workflow and process design, enabling remote monitoring, ex-ecution, and control.

Drilling contractors have swiftly implemented automation, with manual work being replaced by machines and smart software. In the service industry, remote subject-matter experts have re-placed field engineers. These initiatives have contributed significantly to reduc-ing operational cost and have improved service quality and reduced NPT.

The challenge, however, is the human capital—the individual reac-tion to continuous change and where jobs are being moved. Human nature re-sists change and prefers the known, and therefore change processes are some-times impeded by a workforce comfort-able with the status quo. Key personnel that would be the preferred candidates for remote positions often prefer rota-tion cycles in the field. Therefore, intense management focus is required to cause the workforce to commit to the newly de-veloped operations model. Communica-tion and workforce inclusion in all stages of the pre-engineering process are key factors to success. JPT

Fig. 3—All sources of information are recorded by the situational-awareness software, which immediately selects the appropriate sources of information during an event, providing workflows for mitigating action and associated procedures.

DM16999.indd 163 8/19/13 10:36 AM

SPE HONOREES


Austin

Cleon L. DunhamDon R. GeorgeRobert C. MacDonald

Balcones

John D. BoxellWilliam R. LocklearDan A. MageeThomas H. Yates Jr.

Calgary

Patrick D. O'ConnellJohn E. Squarek

Caracas Petroleum

Jesus A. StruveSimon J. Antunez

Colombian

Jose C. Ferrer

Dallas

T.D. BadgwellJames H. LyonMilton D. McKenzieJohn T. MooreAvinash G. NangeaA.W. RitterTommy L. SprinkleFred I. StalkupJames C. Trimble

Delta

Charles V. CusimanoRex C. Hughey

Denver

Jack A. McCartneyForrest M. MooreJames D. Walker

East Texas

James H. Smith

Evangeline

Joy C. Cleveland Jr.Michael J. Veazey

Gulf Coast

Walter W. AllenNathaniel G. BeardDouglas H. BurgessNolan E. CannonElmond L. ClaridgeFielding B. CraftJoseph R. HarrisEdward D. HolsteinClyde G. InksRobert L. KennedyK.T. KoonceHerbert A. LesserGary J. MabieWilliam J. McDonaldDavid G. NussmannCharles R. PeckPaul E. PilkingtonFrank H. RichardsonWayne A. SchneiderRobert S. SingerDavid K. SmithRobert H. StefflerPhilip R. White

Los Angeles Basin

Richard D. FinkenWillis B. Wood Jr.

Mid-Continent

Ronny G. AltmanJames P. BrillAlan W. CarltonCharles A. EllisOran L. HallE.L. Thomas

National Capital

E.H. Herron

North Texas

Edward W. Moran Jr.

Ohio Petroleum

Leo A. Schrider

Oklahoma City

Charles F. BlackwoodRoy M. KnappJeffrey B. RobinsonJohn D. StacyRodney W. Ylitalo

Permian Basin

Barry A. BealBilly J. FeaganAdam Praisnar Jr.

Pittsburgh Petroleum

Robert G. SmithRobert W. Watson

Salt Lake Petroleum

Donald C. Condie

Saudi Arabia

Omar J. Esmail

Southwest Texas

Joaquin V. ArredondoJerry F. Priddy

Trans-Pecos

Michael J. DeMarco

Unassigned–Eastern North America

David W. KeefeNeal Rudder

Unassigned–Southwestern North America

Ron J. Byrd

Unassigned–Western North America

Edward R. McDowell

Wyoming Petroleum

Norman R. Morrow

Legion of HonorSPE welcomes 83 members into the Legion of Honor, which celebrates 50 years of consecutive membership in the Society. Each honoree becomes dues exempt and receives a certificate marking the milestone. The honorees are listed below under their respective sections.

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PEOPLE


PATRICK ALLMAN-WARD, SPE, was appointed chief executive officer of Dana Gas. He has more than 30 years of experi-ence in the oil and gas industry and has held several senior level positions. He joined the company in 2012 as the general manager of Dana Gas Egypt. Allman-Ward began his

career with Shell where he gained experience in a wide range of departments, including exploration; planning; business devel-opment; commercial negotiations; and health, safety, security, and the environment. He earned a BS in geology from Durham University and a PhD from the Royal School of Mines, Univer-sity of London.

ROB BUCHAN, SPE, was appointed Aber-deen general manager at GDF SUEZ E&P UK and will oversee the company’s develop-ments and operations across the UK. Before joining the company in 2008, he worked with Dowell Schlumberger on international assignments and with BP for 24 years in

drilling and operations management roles in Aberdeen and London. He earned a BS in geology from Aberdeen University and an MBA from Robert Gordon University.

GREGORY K. GRAVES, SPE, was promot-ed to senior vice president at DeGolyer and MacNaughton. He will continue to lead the Houston office and direct a team that works on projects in North America. Graves spe-cializes in reservoir engineering and has a geology background coupled with experi-

ence in investment banking, finance, and economics. Before joining the company, Graves worked with a number of energy companies, including Devon Energy, where he served as the supervisor of international exploitation for the Middle East and Asia regions. He is a licensed professional engineer in Texas. He earned a BS in petroleum engineering from The Uni-versity of Texas at Austin and completed post-baccalaureate studies in microeconomics and macroeconomics at the Univer-sity of Houston.

JAY HOLLINGSWORTH, SPE, has joined Energistics as its chief technology officer. Hollingsworth has more than 20 years of upstream oil and gas industry experience. He held technical management positions at Oracle, Schlumberger, Landmark, and Mobil Oil. His experience includes a wide range of

data architecture and database engineering technologies as well as knowledge of geosciences and engineering. Hollingsworth earned a BS in chemical engineering from Tulane University and a BS in computer science from the University of Texas at Dallas.

DILHAN ILK, SPE, was promoted to vice president at DeGolyer and MacNaughton. He joined the company in 2010 and spe-cializes in well performance evaluation and forecasting. Ilk has written more than 30 articles in well test analysis, analysis/inter-pretation of production data, and general

reservoir engineering and has carried out field projects ana-lyzing well performance data in fields in Venezuela and North America. He earned a BS in petroleum engineering from Istan-bul Technical University and an MS and a PhD in petroleum engineering from Texas A&M University.

ARUN KHARGHORIA, SPE, was promoted to vice president at DeGolyer and MacNaugh-ton. He joined the company in 2009 and has directed and contributed to projects in Rus-sia, Algeria, Malaysia, Colombia, Ghana, and the US. Before joining the company, Kharg-horia worked for several oil and gas consul-

tants in positions including reservoir engineering adviser and senior reservoir engineer. He has carried out research assign-ments for Texas A&M University and the University of Tulsa. Kharghoria earned a BS in technology from the Indian School of Mines, an MS in petroleum engineering from the University of Tulsa, and a PhD in petroleum engineering from Texas A&M Uni-versity. He was given an Outstanding Technical Editor award by the SPE Editorial Review Committee in 2008.

JAMES J. KLECKNER, SPE, was promoted to executive vice president of Anadarko Petroleum. Previously, he was the vice presi-dent of operations for Anadarko’s Rocky Mountain region, overseeing the company’s operations and development activities in Col-orado, Utah, and Wyoming. Kleckner has

more than 30 years of global technical and leadership experience. He began his career in the oil and gas industry with Sun Oil and has held management positions in the North Sea, South America, China, the Gulf of Mexico, and the US. Kleckner earned a BS in petroleum engineering from the Colorado School of Mines.

IGOR P. MOSKVIN, SPE, was promoted to vice president at DeGolyer and MacNaugh-ton. He joined the company in 2005 and specializes in reservoir engineering and simulation studies and estimating hydrocar-bon reserves. His prior experience includes working for Yukos in the Department of

Technological Project Appraisal at the Moscow Technology Center and working for a major Russian oil and gas company on an annual reserves update that included an analysis of 88 fields. He earned a BS in petroleum engineering from the Tomsk Poly-

PeopleSept.indd 167 8/12/13 2:33 PM

PEOPLE


technic University and an MS in petroleum engineering from Heriot-Watt University.

GARY C. ROBINSON, SPE, was promoted to vice president at DeGolyer and Mac-Naughton. He joined the company in 2009 as a geologist who works on reservoir stud-ies projects worldwide. Before joining the company, Robinson worked for geophysical companies, including Denver Geophysical,

CGG, RC Squared, and Veritas as well as oil and gas companies, including Saudi Aramco and Eastern American Energy. He

coauthored 21 technical papers, holds two patents for seismic applications, and was awarded a Certificate of Merit by the Soci-ety of Exploration Geophysicists. He earned a BS in geology from Stanford University and an MS in geophysics from the Uni-versity of Houston.

JAMES A. WATSON, SPE, will join ABS as president and chief operating officer of its Americas division. In his new position, Wat-son will oversee activities in North, South, and Central America and the Caribbean. Before joining ABS, he served as director of the US Bureau of Environmental Safety and

Enforcement and as the director of prevention policy for marine safety, security, and stewardship at the US Coast Guard. Watson earned a BS degree in marine engineering from the US Coast Guard Academy, MS degrees in mechanical engineering and in naval architecture from the University of Michigan, and an MS degree in strategic studies from the Industrial College of the Armed Forces.

Member Deaths William D. Carson, Naperville, Illinois, USAK.J. Feyhl, Billings, Montana, USAJ.V. Fredd, Plano, Texas, USAJesse P. Johnson, Richardson, Texas, USALeonard McCasland, Prosper, Texas, USA

In Memoriam

GEORGE P. MITCHELL, SPE, a pioneer in developing methods to produce shale gas economically, died 26 July in Galveston, Texas. He was 94.

Mitchell earned a BS in petroleum engi-neering with an emphasis in geology from Texas A&M University. After graduation, he

worked for a few years at Amoco before serving as a captain in the US Army Corps of Engineers during World War II. Afterward, he joined a wildcatting company. He later bought out his part-ners, and the company evolved into Mitchell Energy and Devel-opment, which became one of the nation’s largest independent oil and gas companies. In 2002, it merged with Devon Energy.

Mitchell is best known for his involvement in combining hydraulic fracturing and horizontal drilling in the Barnett Shale development that led to the current shale gas revolution.

“Big oil companies knew the upside potential of shale gas, and many were working to economically extract the gas from the shale without much success,” Mitchell said in an inter-view with The Economist magazine. “Many people were try-ing to make hydraulic fracturing work better, but they were not able to get the cells to give up the gas. We knew there was gas in some of these shale fields. We would measure the volume of gas in the reservoir and it was very high methane (25-40% methane). You could get to the methane, but you could not get it to leave the cells until you fractured it, and that was the major breakthrough.

“We invested approximately USD 6 million over a 10-year period in the 1980s and 1990s to make fracturing an economi-

cally viable process. I never considered giving up, even when everyone was saying, ‘George, you’re wasting your money.’”

As a result of his contributions to the oil and gas industry, he was awarded a Lifetime Achievement Award from the Gas Technology Institute.

“George Mitchell, more than anyone else, is responsible for the most important energy innovation of the 21st century,” said Daniel Yergin, vice chairman of consulting firm IHS and a Pulit-zer Prize winning author on energy. “Before his breakthrough, shale gas had another name—‘uneconomic’ gas. It was thought that there was no way to commercially extract it. He proved that it could be done. His breakthrough in hydraulic fracturing, when combined with horizontal drilling, set off the revolution in unconventional oil and gas that we see today. But it did not come easily. It took a decade and a half of conviction, investment and dogged determination. In the face of great skepticism and refus-ing to accept ‘no’ as an answer, Mitchell dramatically changed America’s energy position. As such, he also changed the world energy outlook in the 21st century and set in motion the global rebalancing of oil and gas that is now occurring.”

Mitchell also led real estate and community development projects. In 1974, his company developed The Woodlands, a 27,000-acre forested, master-planned community north of Houston. He also founded the Houston Advanced Research Center, a collaboration among eight universities and research groups dedicated to sustainable development.

Mitchell’s wife, Cynthia, died in 2009. He is survived by three daughters, seven sons, a sister, 23 grandchildren, and five great-grandchildren.

PeopleSept.indd 168 8/12/13 2:33 PM

SPE NEWS


SPE Implements Staff Reorganization SPE recently implemented significant changes in its staff structure to maximize staff resources for future growth in programs and services. The new organizational struc-ture regroups and consolidates activities from functional departments as well as SPE’s regional offices to provide a more seamless global staff operation. The revised struc-ture will enhance collaboration, effectiveness, and internal communications; provide a more efficient leadership structure; and address operational challenges that have emerged as a result of the Society’s rapid growth in recent years.

Four members of the staff leadership team were named to new positions in the reorganization, announced 15 July:

◗◗ Georgeann Bilich, Vice President Communications◗◗ Steve Byrne, Chief Financial Officer◗◗ Roberto Chiarotti, Vice President Sales and Marketing◗◗ Stephen Graham, Chief Operations Officer (COO)

A fifth new position, Vice President Member and Information Services, will com-plete the new staff executive team reporting to Mark Rubin, now CEO and Executive Vice President. That new position combines member services and information-tech-nology services into a new division, where Jane Boyce and Walter Jacinto continue as Director Member Services and Director Information Technology, respectively.

As COO, Graham leads SPE’s global operations team, with emphasis on strategic initiatives and execution of events—conferences, exhibitions, workshops, and training courses. Named to new positions in this group are:

◗◗ Solange Ferreira, Assistant Director Latin America and the Caribbean ◗◗ Ken Leonard, Assistant Director Global Training

Also part of this group are:◗◗ Waleed Refaay, Managing Director Middle East, North Africa, and India◗◗ Niki Thomas, Managing Director Russia and Sub-Sahara Africa◗◗ Cordella Wong-Gillett, Managing Director Asia Pacific

A new position for Managing Director North America has yet to be filled.

In additional changes, several senior managers were named to new positions:◗◗ John Donnelly, Director Magazines and Web Content. Donnelly will also

remain JPT Editor.◗◗ Holly Hargadine, Assistant Director Technical Activities◗◗ Suzette Lawniczak, Assistant Director Human Resources ◗◗ Craig Moritz, Assistant Director Americas Sales and Exhibits◗◗ Glenda Smith, Director Innovation, Strategy, and Analytics

SPE last evaluated its staff structure in 2007 and implemented changes to meet the changing landscape. Since then, the Society’s growth has been dramatic—doubling the number of staff positions, adding 37,000 new members, more than doubling reve-nue, and adding many new programs and activities. Additional organizational changes within departments to streamline processes and responsibilities are under way.

SPE SERVICE DIRECTORY

SPE Online www.spe.org

Awards Program Tom Whipple, [email protected] Phone: 1.972.952.9452

Book Sales Phone: 1.800.456.6863 or 1.972.952.9393 [email protected]

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Dues, Membership Information, Address Changes, Copyright Permission Phone: 1.800.456.6863 or 1.972.952.9393 [email protected]

Insurance/Credit Card Programs Liane DaMommio, [email protected] Phone: 1.972.952.1155

JPT Professional Services Evan Carthey, [email protected] Phone: 1.713.457.6828

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Professional Development Services Tom Whipple, [email protected] Phone: 1.972.952.9452

Section Service Phone: 1.972.952.9451 [email protected]

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Subscriptions Phone: 1.800.456.6863 or 1.972.952.9393 [email protected]

Americas Office 222 Palisades Creek Dr., Richardson, TX 75080-2040 USA Tel: +1.972.952.9393 Fax: +1.972.952.9435 Email: [email protected]

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Moscow Office Perynovsky Per., 3 Bld. 2 Moscow, Russia, 127055 Tel: +7.495.268.04.54 Email: [email protected]

SPENewsSept.indd 169 8/13/13 9:30 AM

SPE NEWS


SPE’s The Way Ahead Magazine Seeks Young Professionals to Serve as Editors Are you creative? Do you write English well? Are you passionate about the world’s struggle to find and develop energy sources? Do you love to learn about different per-spectives from all over the world?

SPE’s unique and respected The Way Ahead magazine seeks enthusiastic young professionals to commit to become a member of the magazine’s editorial commit-tee. You would work from your home base with young professionals worldwide to develop and deliver articles on a wide range of topics. You would plan an article, con-tact authors or interviewees, edit the article, give monthly progress reports, and be responsible for making sure the work is carried out within the time allotted and to high standards.

Here is how to apply for a position on The Way Ahead editorial committee:◗◗ Prepare a single-page résumé that includes SPE and other volunteer activities

that reflect your ongoing commitment to serve as a volunteer.◗◗ Write a concise, 200-word essay stating the main reasons that drive you to

apply to participate. Then just send your application and any questions to [email protected].

SPE Dallas Section 2013 Mid-Continent Regional Awards were presented in June at the monthly section meeting at Brookhaven College in Farmers Branch, Texas. Brian Chacka, left, accepted the Distinguished Corporate Support Award on behalf of Denbury Resources, located in Plano, Texas. Michael Tunstall (current Mid-Continent Regional Director) and Dan Auces both received Service Awards; Brad Robinson received the Completions Optimization and Technology Award; Kelly Blackwood received the Young Member Outstanding Service Award; and Ricky Williams received the Production and Operations Award. Also pictured is Terry Palisch, the Dallas Section Chair. PV (Suri) Suryanarayana, not shown, received the Drilling Engineering Award.

SPENewsSept.indd 170 8/19/13 10:37 AM

SPE EVENTS


WORKSHOPS

23–24 September ◗ Bogota Petroleum and Unconventional Resources Reserves: Understanding the Economic, Technical, Environmental, and Regulatory Aspects

24–26 September ◗ Istanbul—Energise Your Future: Building Blocks for Future Oppotunities

6–9 October ◗ Kota Kinabalu—Chemical EOR—Industry Best Practices and Latest Advancement

16–18 October ◗ Banff—Production Forecasting

21–22 October ◗ Dubai—Petroleum Reserves and Resources Estimation and its Impact on Business Decisions—PRMS Applications Guidelines Document

22–23 October ◗ Galveston—Water Lifecycle

27–30 October ◗ Ho Chi Minh—Reservoir Modelling and Simulation—Challenges and Latest Development

28–29 October ◗ Abu Dhabi—Flow Assurance: Challenges and Integrated Solutions for Mature and Green Fields

28–29 October ◗ Doha—Emerging Trends in Corrosion Management—Stretching the Envelope

28–30 October ◗ Dubai—Addressing and Solving the Petrophysical Challenges Specific to Middle East Reservoirs

5–7 November ◗ Lisbon—North Sea and Europe Area Stimulation

6–7 November ◗ San Antonio—Hydraulic Fracture Flowback

6–8 November ◗ Denver—Collision Avoidance and Well Interceptions

13–14 November ◗ Oslo,Norway— Flow Assurance: Tackling Tomorrow’s Challenges

12–14 November ◗ Rome— Real-Time Decisions While Drilling

17–19 November ◗ Banff—Thermal Well Integrity

17–20 November ◗ Kota Kinabalu—Offshore Facilities

17–20 November ◗ Lisbon—Beyond Closed Loop Integrated Monitoring

18–20 November ◗ Mumbai—Deepwater: Promising Potential—Difficult Dynamics

18–20 November ◗ Bangkok—Young Professionals Workshop

24–27 November ◗ Phuket—Artificial Lift Systems—Get the Maximum from your Wells

25–27 November ◗ Larnaca—Unconventional Gas Fracturing: Integrating Disciplines to Develop Regional Best Practices

26–28 November ◗ Tyumen—Waterflood Optimisation on Mature Fields

1–3 December ◗ Kuala Lumpur—SPE Workshop on R&D

2–5 December ◗ Lisbon—Integrated Water Management—Brownfield to Greenfield and Back Again

8–11 December ◗ Bali—Institutionalising Smart/Digital Fields Capability

cONfeReNceS

30 September–2 October ◗ New Orleans—SPE Annual Technical Conference and Exhibition

7–9 October ◗ Dubai—SPE/IADC Middle East Drilling Technology Conference and Exhibition

7–10 October ◗ Kuwait City—SPE Kuwait Oil and Gas Show and Conference

15–17 October ◗ Moscow—SPE Arctic and Extreme Environments Technical Conference and Exhibition

21–23 October ◗ Alexandria—Carbon Management Technology Conference

22–24 October ◗ Jakarta—Asia Pacific Oil and Gas Conference and Exhibition

28–30 October ◗ Dubai—Intelligent Energy International Conference and Exhibition

29–31 October ◗ Rio de Janeiro— OTC Brasil

5–7 November ◗ Calgary —SPE Unconventional Resources—Canada

11–13 November ◗ Brisbane—SPE Unconventional Resources Conference and Exhibition—Asia Pacific

fORUMS

13–18 October ◗ Vilamoura—Adaptive Well Construction

20–25 October ◗ Vilamoura—Managed Pressure Drilling—Niche Technology or the Future of Drilling?

20–25 October ◗ Rancho Mirage—Artificial Lift in Deepwater

19–22 January 2014 ◗ Doha—International Petroleum Technology Conference

16– 21 february 2014 ◗ Vilamoura—Zonal Isolation to the Extreme

cALL fOR PAPeRS

Improved Oil Recovery Symposium ◗ Tulsa, Oklahoma, USA Deadline: 26 September 2013

SPe eOR conference and Oil and Gas West Asia ◗ Muscat, Oman Deadline: 5 October 2013

SPe International Oilfield Scale conference and exhibition ◗ Aberdeen, UK Deadline: 7 October 2013

SPe Hydrocarbon economics and evaluation Symposium ◗ Houston, Texas, USA Deadline: 17 October 2013

IADc/SPe Asia Pacific Drilling Technology conference ◗ Bangkok, Thailand Deadline: 8 January 2014

Middle east Health, Safety, environment and Sustainable Development conference and exhibition ◗ Doha, Qatar Deadline: 6 February 2014

SPe Asia Pacific Oil and Gas conference and exhibition ◗ Adelaide, Australia Deadline: 10 January 2014

SPe Annual Technical conference and exhibition ◗ Amsterdam, the Netherlands Deadline: 27 January 2014

Find complete listings of upcoming SPE workshops, conferences, symposiums, and forums at www.spe.org.

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2013-09JPT Magazine

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