Caspian oil

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COVER PHOTOAn aerial photo of the Yuri

Korchagin field in the Russian

sector of the north Caspian Sea.

Photo courtesy of Lukoil.

JPT Staff

Glenda Smith, Publisher

John Donnelly, JPT Editor

Abdelghani Henni, JPT Middle East Editor

Dennis Denney, Contributing Writer

Ngeng Choo Segalla, Copy Editor

Alex Asfar, Senior Manager Publishing Services

Mary Jane Touchstone, Print Publishing Manager

Stacey Maloney, Print Publishing Specialist

Laurie Sailsbury, Composition Specialist Supervisor

Allan Jones, Graphic Designer

Craig Moritz, Assistant Director Americas Sales & Exhibits

2 SPE IN THE CASPIAN REGIONSPE has an active presence in Russia and the Caspian region, where it serves its members through 18 active sections and 27 student chapters.

3 UNCOVERING THE CASPIANThe Caspian Sea region is the birthplace of the oil and gas industry, as the world’s first offshore wells and machine-drilled wells were made in Bibi-Heybat Bay, near Baku, Azerbaijan.

4 RAISING THE BARWith a major ongoing expansion campaign, Kazakhstan has set its sight on becoming one of the world’s largest oil and gas producers.

8 TECHNOLOGY AND R&D ROAD MAPA collaborative industry strategic framework outlines a technology vision for the Kazakhstan upstream oil and gas industry.

10 LOCAL MOTIONAbat Nurseitov, chief executive officer of KazMunaiGas Exploration Production JSC, highlights the operations of his company and Kazakhstan and says the era of easy oil is over.

12 THE MYSTERY OF KASHAGANAn international consortium is working to develop the Kashagan field, one of the largest discoveries in decades.

15 POWER OF TWODaniele Bertorelli, executive vice president, Central Asia, Eni, discusses the involvement of his company in the two major oil fields in Kazakhstan, Karachaganak and Kashagan, and outlines key opportunities for his company in the country..

17 AZERBAIJAN ENERGIZEDAzerbaijan is among the oldest crude producers in the world, and considered the birthplace of the oil industry.

21 PRIVATE POWERFedor Klimkin, a manager at Lukoil Overseas, says his company will continue to be a key player in the Kazakhstan oil and gas industry as it produces about 10% of the country’s total oil production.

23 GAS FOR CASHTurkmenistan has tremendous gas reserves, but hurdles on the foreign investment front are keeping the country’s development plans in limbo.

27 LOOKING AHEADAlex Dodds, executive vice president of exploration and production at Hungarian MOL Group, says developments in the Caspian region will have a positive effect on his company’s mid-term and long-term production growth.

TECHNICAL PAPERS

29 HANDLING UNCERTAINTY ANALYSIS IN A BROWNFIELD

32 SAND-CONTROL RELIABILITY OF OPENHOLE GRAVEL-PACK COMPLETIONS

35 REAL-TIME CASING-RUNNING ADVISORY SYSTEM REDUCES NONPRODUCTIVE TIME

38 BOTTOMHOLE ASSEMBLY IMPROVES EXTENDED-REACH-DRILLING RATE OF PENETRATION BY 62%

UNCOVERING THE CASPIAN

2 UNCOVERING THE CASPIAN

The Society of Petroleum Engineers (SPE) has an active

presence in Russia and the Caspian region, where it

serves its members through 18 active sections and 27

student chapters. The Society reaches its members in the

Caspian region through its office in London, and its Russia-

based members from its office in Moscow.

At the end of 2013, SPE’s total professional and

student membership stood at 124,528, with the Russia and

Caspian region posting one of the highest growth rates. With

more than 500 professional and 600 student members, the

Caspian region is one of the Society’s most dynamic growth

areas with five active sections and six university chapters.

SPE has organized successful events in the Caspian

region including the Caspian Carbonate Technology Workshop

in Kazakhstan and the Sand Control in Poorly Formulated

Consolidations Workshop in Azerbaijan, which was extremely

successful with 108 international and regional attendees

from 29 organizations and universities. Being the first

technical SPE workshop in Azerbaijan, this event facilitated

networking opportunities for professionals both within and

outside the region.

For the first time in the Caspian region, SPE will be

organizing the Annual Caspian Technical Conference and

Exhibition (CTCE) in Astana, Kazakhstan, during 12-14

November. The event will include 18 technical sessions and 4

high-level panel sessions.

The CTCE will be the first event in Kazakhstan where

international and local operators and service companies will

meet to discuss and listen to leading technical papers given

by the top professionals in the industry. Keynote speakers

will include representatives from the Ministry of Energy, the

Republic of Kazakhstan, and Shell Kazakhstan. There will

also be high-profile speakers from KazMunayGaz, Kazenergy,

Karachaganak Petroleum Operating B.V., Tengizchevroil,

North Caspian Operating Company, Chevron, and ExxonMobil.

The technical program will consist of 18 parallel sessions

covering topics such as drilling and completions, reservoir

management, artificial lift operations, environmental

stewardship, and well intervention.

This event is part of SPE’s global mission, which

aims to collect, disseminate, and exchange technical

knowledge related to the exploration, development, and

production of oil and gas resources, and related technologies

for the public benefit. It also provides opportunities for

energy professionals to enhance their technical and

professional competence.

Among the many activities and opportunities that SPE

provides to support the industry are several publications,

such as the Journal of Petroleum Technology, Oil and Gas

Facilities, and The Way Ahead; conferences, workshops,

and forums; a Distinguished Lecturer program; an annual

international awards program; and scholarships to help

students in pursuing their studies. SPE’s many conferences,

exhibitions, workshops, and section meetings serve to help

increase the technical knowledge of participants and as

networking opportunities for professionals to meet and

exchange ideas with their peers.

SPE welcomes new members throughout the region and

encourages industry professionals to join their local section

or to learn how they can start a new section in geographic

locations not currently supported. Visit the SPE website,

www.spe.org/join/ to join and you will immediately benefit

from the following:

◗ Discounted member registration to attend

conferences, workshops, and training courses with

direct access to innovative technologies, technical

knowledge, and interaction with colleagues to help you

continue your professional development

◗ Special pricing on books and subscriptions to SPE

periodicals

◗ Access to OnePetro, one of the industry’s largest

online technical libraries, allowing you to search,

purchase, and download more than 90,000 technical

documents from multiple professional societies

◗ Opportunities to present technical papers in a journal

or at a conference to share knowledge with your peers

◗ Leadership and volunteer opportunities to help you

build industry relationships

◗ A number of career development tools, from training

to technical sections to e-mentoring and more

◗ Complimentary subscription to the Journal of

Petroleum Technology (JPT).

UPCOMING EVENTS

(Volunteer – Speak – Attend – Exhibit):

12–14 November 2015 ∫ Astana, Kazakhstan

Annual Caspian Technical Conference and Exhibition

Website: www.spe.org/events/ctce/2014

SPE IN THE

CASPIAN REGION

For more information on the event listed, please

email [email protected] or call +6.03.2182.3000.

3SUPPLEMENT TO JPT NOVEMBER 2014

UNCOVERING THE CASPIANThe Caspian Sea region is the birthplace of the oil and gas industry, as the world’s first

offshore wells and machine-drilled wells were in Bibi-Heybat Bay, near Baku, Azerbaijan.

In 1873, the exploration and development of oil began in some of the largest fields known

to exist in the world at the time on the Absheron peninsula near the villages of Balakhanli,

Sabunchi, Ramana, and Bibi Heybat.

ABDELGHANI HENNI, JPT MIDDLE EAST EDITOR

he Caspian Sea is not a sea but a

giant lake that spans approximately

1000 km (600 miles) from north

to south. The coastlines are shared by

Azerbaijan, Iran, Kazakhstan, Russia, and

Turkmenistan. The Caspian is divided

into three distinct physical regions: the

northern, middle, and southern Caspian.

More than 130 rivers provide inflow to the Caspian, with

the Volga River being the largest. A second affluent river, the

Ural River, flows in from the north, and the Kura River flows into

the sea from the west. In the winter, ice often forms over the

lake’s northernmost reaches, while the central and southern

parts remain ice-free, because the water is saltiest in the

south and freshest in the north. The combination of ice, shallow

water, and sea level fluctuations represents a significant

challenge for oil and gas companies operating in the region.

The Caspian Sea is rich in hydrocarbon resources and

the littoral states of the sea have made great investment in

developing oil fields in the region over the past few years. In

2012, the United States Energy Information Administration

estimates that there are 48 billion bbl of oil and 292 Tcf

of natural gas in proved and probable reserves within the

basins that make up the Caspian Sea and surrounding area.

Offshore fields account for 41% of total Caspian crude oil

and lease condensate (19.6 billion bbl) and 36% of natural

gas (106 Tcf). In general, most of the offshore oil reserves

are in the northern part of the Caspian Sea, while most of

the offshore natural gas reserves are in the southern part.

In addition, the US Geological Survey estimated

another 20 billion bbl of oil and 243 Tcf of natural gas in

as yet undiscovered, technically recoverable resources.

Much of this is located in the South Caspian basin, where

territorial disputes over offshore waters hinder exploration.

The legal questions about the status of the Caspian

Sea, as it is not considered a “sea” subject to the United

Nations Convention on the Law of the Sea, have on

occasion been presented as a major obstacle to Caspian

energy investment and trade. In practice, legal uncertainty

has hindered but not prevented oil and gas development.

An overall legal framework for the Caspian Sea would be

useful, but does not appear to be imminent. Bilateral political

relationships are likely to be more important in settling

outstanding legal questions and determining the direction

and nature of future oil and gas flows across the Caspian.

While most current Caspian oil comes from onshore

fields, the biggest prospects for future growth in production

are from offshore fields, which are still relatively undeveloped.

Chief among them is Kazakhstan’s Kashagan field, believed

to be the largest known oil field outside the Middle East. The

Caspian area produced 2.8 Tcf of natural gas in 2012, with large

portions reinjected into fields or flared. The large amount and

dispersed nature of the Caspian natural gas reserves suggest

the possibility of significant future growth in production.

Azerbaijan became an important regional natural gas

producer with the start of production in the Shah Deniz field

in 2006. Other prospects for natural gas production growth

include Russia’s north Caucasus region, which has the bulk

of the Caspian Sea region’s onshore natural gas reserves,

and Turkmenistan’s Galkynysh field, which may be the world’s

fourth largest natural gas field as suggested by a 2009 audit.

In addition, there are sizable deposits under development

in the Russian offshore section of the Caspian Sea. For

example, in the Lukoil-operated Yuri Korcharin oil and gas field,

discovered in 2000, production started in 2010 and is expected

to plateau at 50,000 BOPD, and the large Vladimir Filanovsky

field, discovered in 2005, may produce as much as 210,000

BOPD by 2015–16. Other recent offshore discoveries in the

Russian Caspian will strengthen Russia’s engagement in the

region and stimulate development in Astrakhan, Makhachkala,

and Budennovsk in southern Russia and the northern Caucasus.

Iran has also recently announced its first exploration

success off its Caspian shore. In July 2012, the country

discovered a new oil layer with in-place reserves of 2 billion

bbl in Sardar-e Jangal oil and gas field offshore its northern

province of Gilan. The preliminary evaluations showed that

Sardar-e Jangal field would produce approximately 8,000 BOPD

and its gas reserves were estimated at 50 Bcf, a quantity

equivalent to Iran’s total gas consumption over a 10-year period.

Caspian oil and natural gas fields are relatively far from

export markets, requiring expensive infrastructure and large

investments to transport produced hydrocarbons to markets.

The Caspian Sea’s periodically freezing waters increase the costs

of offshore projects, and shifting regulations create uncertainty

for foreign companies investing in natural resources in the region.

In the well-supplied oil and gas markets of the ’90s,

Caspian oil and gas reserves were stranded resources, and

their significance was largely regional where the Caspian

oil and natural gas went directly to Russia through Soviet

infrastructure, such as the Central Asia–Center gas pipeline

system, where some could go to Western markets, but after

T

JUMP TO PAGE 20

RAISING THE BAR

KAZAKHSTAN


MALAYSIA—REACHING SKYWARD

Kazakhstan has vast reserves of natural resources and fossil fuels, many of which

are untapped. According to BP’s Statistical Review of World Energy 2014, Kazakhstan has proved reserves estimated at 30 billion bbl of oil and proved natural gas reserves of 1.5 Tcm, which represent 1.8% and 0.7% of total global reserves, respectively.

Kazakhstan, the second largest oil producer among the former Soviet republics after Russia, is heavily reliant on oil export revenues. Total production of oil and gas condensate in 2013 amounted to 81.8 million tons, up 3.2% compared with 2012, of which 72.1 million tons were exported.

The government expects total production to rise to 90 million tons in 2015 and 110 million tons in 2018. According to the International Energy Agency’s World Energy Outlook 2010, Kazakhstan will join the top oil and gas exporters by 2020.

State participation in the oil and gas industry has increased over the past several years because of the vital role of the industry in the economy of the republic. The vertically integrated National Company KazMunay-Gaz represents the state’s interests in the industry. It controls 20% of total oil and gas proved reserves in Kazakhstan, and produces 27% of total oil and gas condensate and 14% of gas.

Oil ProductionKazakhstan produced 1.79 million BOPD last year, according to BP annual

statistics. It has 172 oil fields, of which more than 80 are under development. Fewer than half of the fields are in operation.

More than 50% of oil reserves are concentrated in the three largest oil fields: Tengiz, Kashagan, and Karachaganak. Also, the majority of oil fields are located in six of the 14 provinces, namely Aktobe, Atyrau, West Kazakhstan, Karaganda, Kyzylorda, and Mangystau. Approximately 70% of the hydrocarbon reserves are concentrated in western Kazakhstan.

According to the Ministry of Oil and Gas, the Atyrau province holds the most significant number of oil fields, in which more than 75 fields have commercial reserves of 930 million tons. The largest field in the province is Tengiz (with 781 million tons of initial recoverable reserves). The remaining fields have approximately 150 million tons of initial recoverable reserves. More than half of those are concentrated in two fields: Korolevskoye (55.1 million tons) and Kenbai (30.9 million tons).

Another promising region with oil and gas potential is the Aktobe province. So far, about 25 fields have been discovered there. The most important geological discoveries are the Zhanazhol group of fields with recoverable oil and condensate reserves amounting to approximately 170 million tons.

Major DevelopmentKazakhstan has set its sights on becoming one of the world’s biggest oil and gas producers by focusing on its major fields, mainly Tengiz and Kashagan, and the Eurasia project.

Located in western Kazakhstan, Tengiz is the world’s deepest operating

supergiant oil field, with the top of the reservoir at approximately 12,000 ft (3657 m) below ground. Chevron holds a 50% interest in Tengizchevroil (TCO), which operates the field. The partnership also is developing the nearby Korolev field.

The net daily production in 2013 averaged 243,000 bbl of crude oil, 347 MMcf of natural gas, and 20,000 bbl of natural gas liquids. Most of the crude oil production is exported through the Caspian Pipeline Consortium pipeline. The balance was exported by rail to the Black Sea ports. In 2012, TCO produced its 2 billionth bbl of crude oil from the Tengiz and Korolev fields since its inception in 1993. In November 2013, the government signed a memorandum of understanding with TCO to expand its operations in the Tengiz field.

Last year, front-end engineering and design work began on three projects. The Wellhead Pressure Management Project is designed to maintain production capacity at existing facilities, and the Capacity and Reliability Project (CRP) is designed to reduce bottlenecks and increase plant efficiency and reliability at TCO facilities. The third project, the Future Growth Project (FGP), is designed to increase total daily production by 250,000 BOE to 300,000 BOE and to increase the ultimate recovery of the reservoir. Costing USD 20 billion, the FGP will expand its production in the Tengiz field by nearly 150% to between 850,000 BOPD and 900,000 BOPD by 2020.

A final investment decision on the CRP was made in February. Final investment decisions on the other

With a major ongoing expansion campaign, Kazakhstan has set its sights on becoming one of the world’s largest

oil and gas producers. ABDELGHANI HENNI, JPT MIDDLE EAST EDITOR

Left, A gas processing unit at the Karachaganak field in Kazakhstan. Photo courtesy of Lukoil.

KAZAKHSTAN—RAISING THE BAR


projects are planned for the second half

of the year.

Another important highlight of last

year was the announcement of the

new Eurasia project, which will be no

less important and profitable than

the Kashagan field. It involves the

exploration of the deep horizons of

the Caspian basin, both on land and

at sea in both Kazakhstan and Russia.

Undoubtedly, this project created

serious interest among representatives

of global oil companies, experts, and

bankers. Everyone understood that the

implementation of this idea opens up

new possibilities.

In October 2013, Kazakhstan Oil

and Gas Minister Uzakbay Karabalin

said that the implementation of the

Eurasia project will double Kazakhstan’s

hydrocarbon reserves. Prospectors

will have to explore deeper layers of

subsoil. “The depth of the Caspian

basin is 20 000 to 25 000 m and there

are huge amounts of oil-generating

formations there. In Soviet Kazakhstan,

there were attempts to drill ultradeep

wells: Aralsorsk and Bikzhalsk. In those

years and with the technology of the

time, wells reached a depth of almost

7000 m, which was considered a good

success. Now, the basin’s potential

shows that additional deposits of

interest can be found even deeper,”

he said.

The Eurasia will consist of three

stages. The first involves the collection

and processing of material from

previous years, the second includes

large-scale studies, and the third entails

the drilling of a new support parametric

well, the Caspian-1, with a depth of 14

km to 15 km. The total estimated cost of

the project is about USD 500 million.

The project may be implemented by

an international consortium comprising

a number of major oil companies.

Firms that have expressed interest

include those from Kazakhstan, Russia,

Japan, South Korea, and China, as well

as the West. Future members of the

consortium will have to jointly create a

research program and provide financing,

and the project will be managed in

Kazakhstan. The launch of Eurasia is

scheduled for 2015. Until then, a group

will be established to negotiate with

potential project participants.

Gas Production

Rising natural gas production over

the past decade has both boosted

oil recovery (as a significant volume

of natural gas is reinjected into

oil reservoirs) and also decreased

Kazakhstan’s reliance on imports.

The growth of natural gas

development has lagged oil because

of the lack of a domestic gas pipeline

infrastructure linking the western

producing region with the eastern

industrial region, and the lack of

export pipelines.

According to the Statistical Review of

World Energy, Kazakhstan holds 1.5 Tcm

of natural gas and produced 18.4 Bcm

in 2013. Most of Kazakhstan’s natural

gas reserves are located in the west,

with roughly 25% of proved reserves in

the Karachaganak field.

The country’s natural gas is almost

entirely “associated” gas, meaning it

is produced with oil. For this reason,

several oil and gas fields including

Karachaganak reinject significant

quantities of gas into the ground to

maintain crude wellhead pressure for

liquids extraction. In the long term,

when the liquids are exhausted, the gas

can be recovered.

The Karachaganak oil and gas

field produced more than 30% of

Kazakhstan’s total dry gas, and Wood

Support facilities at the Kashagan field in Kazakhstan include a bacterial sewage unit and two electrically driven Alfa Laval

freshwater distillers. Photo courtesy of North Caspian Operating Company (NCOC).


Mackenzie expects that dry gas

production from the field will reach

1 Tcf in 2021.

The Tengiz oil and gas field produced

approximately 347 MMcf/D of dry

natural gas in 2011, according to

Chevron. Wood Mackenzie projects

that the field will continue to play a

significant role in Kazakhstan’s gas

production, which will peak at 701 Bcf

of dry gas in 2017 and fall to 532 Bcf

by 2021.

The remainder of the gas produced

in Kazakhstan comes from other

smaller fields. The development of

the Kashagan and Imashevskoye

fields is important to Kazakhstan’s

energy security, as gas output from

them is geared to boost domestic

gas supplies and to provide additional

volumes for enhanced oil recovery.

The two fields together are expected

to provide more than 1 Tcf in dry gas

by 2021.

The lack of an adequate

infrastructure for gas transportation

is causing a problem for the country,

as it is obliged to sell gas to Gazprom.

“Some companies build tie-in gas lines

to the two major trunklines, operated

by KazTransGaz: Bukhara-Ural and

Central Asia-Center. Both trunklines

flow up north to the Russian border

where gas is bought by Gazprom, a

single buyer dictating the price of

USD 70 per 1000 m3,” a well-known

industry source told JPT.

The source said that there

were many attempts not only by

Kazakhstan, but also by Uzbekistan

and Turkmenistan gas producers

to sell their gas to the European

markets at market prices of more

than USD 300; however, the only

route is via Russian GTS belonging to

Gazprom. “All those attempts are

blocked by Gazprom as there is no way

around it. It is the reason for certain

geopolitical activities in the region

where interests of superpowers collide,

including gas pipeline Nabucco,

another attempt to minimize Europe’s

dependence on Russian gas,” the

source said.

Technology Status

Though most of the oil fields are

mature and difficult to recover,

Kazakhstan currently produces only

reachable oil. “We mostly produce

easily reachable oil and old Soviet-

style workover/drilling monster rigs

work,” said Dauren Tukenov, chief

technology officer of Kazakhstan-

based Diversitech.

Tukenov said that Kazakhstan is

using very simple methods in extracting

oil including straight freshwater

flooding, Caspian seawater flooding,

and polymer flooding. In addition, the

country has started steam flooding

tests at some heavy oil deposits. “At the

moment, lifting costs at pumped wells

range from USD 11 to USD 25/bbl,” he

said. “As for enhanced oil recovery in

Kazakhstan, the country is still in early

stages and we haven’t reached the

required recovery level.”

As it is tapping the development

of mature and more difficult fields,

Kazakhstan has launched the upstream

oil and gas technology and research

and development (R&D) road map,

a collaborative industry strategy

framework created to drive the

technology development vision of the

upstream oil and gas industry. “I fully

support the proposal to develop a road

map to strengthen local R&D capacity.

It is important to know what resources

and technologies are needed to

meet the challenges, then which

[Kazakhstan] institutions and

enterprises need to be involved in

tackling each challenge, and who

has to be trained in the required

disciplines,” Kazakhstan President

Nursultan Nazarbayev said at

the Foreign Investors’ Council in

May 2011.

To help Kazakhstan focus on

its R&D efforts and to contribute

to the government’s innovation

agenda, Shell undertook work with

the industry to lead the development

of the country’s upstream

oil and gas technology and R&D

road map.

More than 230 possible

individual technology solutions

were identified in 15 prime

challenge areas and grouped.

The relative value ranking of

the (grouped) solutions was

determined on the basis of their

likely ease of implementation, local

industry opportunities, and their

potential to develop intellectual

capacity in Kazakhstan. JPT


The main development for the Kashagan field in Kazakhstan is a structure named

Island D that is connected with 12 oil wells. Photo courtesy of NCOC.


The oil and gas industry is among the most capital-

and technology-intensive of all industries. The role of

innovation in discovering new reserves and improving

the efficiency of extraction is critical.

Aimed at supporting vital Kazakh oil and gas projects,

investments in research and development (R&D) will also

help to realize the country’s broader industrial and economic

potential. But for innovation to be effective, R&D priorities

must be business-driven and in line with the upstream

industry’s needs.

In order to help Kazakhstan focus on its R&D efforts

and to contribute to the government’s innovation agenda,

Shell jointly with KazMunayGas (KMG) and the Kazakh

Institute of Oil and Gas undertook work with the industry to

lead the development of Kazakhstan upstream oil and gas

technology and create an R&D road map.

A coherent picture of the oil and gas industry is a

prerequisite when making high-level decisions. When the

industry has to decide which technology alternatives to

pursue, how quickly they are needed, or how to coordinate

the development of multiple technologies, road mapping is

essential to controlling capital expenditure and ensuring

cost-efficient R&D activities.

In preparation for the project, the Norwegian approach

to the technological development of the oil and gas

industry was used as a basis. In Norway, local governments

created conditions for close interaction between national

and international oil companies aimed at building local

capabilities and technology transfer.

The Kazakhstan upstream technology and R&D

road map project has become a unique undertaking,

bringing together more than 300 representatives of

the industry toward achieving a collective vision of the

technological development.

This was an excellent opportunity for Kazakhstan’s

R&D organizations to interact directly with operators

and service companies throughout the country and to

share knowledge and experience, and develop a better

understanding of the technology challenges faced by

the industry.

Key Deliverables

The road mapping project achieved a number of important

objectives. The industry collectively identified, screened,

and ranked the main technology challenges based on the

potential financial benefits that could result if they were

successfully addressed.

Potential technology solutions were also identified and

assessed in terms of their effect on solving the challenges

and on their attractiveness to the nation, which included the

consideration of local R&D and industry opportunities.

The project participants collectively developed step-by-

step schemes and milestones for the scientific-technological

development and identified the desired end state of the

upstream oil and gas industry and implementation enablers.

The preliminary estimates indicate that the total value

of successfully addressing all of the 15 challenges in the road

map in the stipulated time frames would be several tens of

billions of US dollars.

Topic Road Maps

More than 230 possible technology solutions were identified

to address the primary challenge areas. Topic road maps

outline the challenges and suggest the best way of

Kazakhstan Upstream Technology and R&D Road Map

A COLLABORATIVE INDUSTRY STRATEGIC FRAMEWORK OUTLINES A TECHNOLOGY

VISION FOR THE KAZAKHSTAN UPSTREAM OIL AND GAS INDUSTRY.


Cranes on Island D, the main processing hub at the Kashagan

oil field offshore Kazakhstan. Photo courtesy of NCOC.


overcoming them by innovation. The road maps clearly show

that a wealth of opportunities exists for the local industry

and academia in Kazakhstan, and for a number of areas in

which skills need to be developed.

In accordance with the Kazakh president’s instructions,

the local government was tasked to organize the

implementation of the road map. Foreign investors were

invited to participate in addressing the direction of the

identified priority technologies and to help plan specific steps

to ensure an accelerated introduction of new technologies,

the forming of scientific cooperation and scientific and

production links, and the planning of technical training

programs in the disciplines demanded by the industry in the

medium and long terms.

Major operators and companies will coordinate the

activities in the selected technology target areas following

the example of Shell, which facilitates the interface within

reservoir characterization, providing a forum for the

knowledge exchange of novel technological solutions and

hastening technology development in the industry.

Such an approach is successfully applied in Norway

where companies combine their efforts in addressing the

priority technology target areas, thus contributing to the

sustainable development of the oil and gas industry.

Transfer of Technology

Shell, jointly with KMG and its newly established Scientific-

Research Institute for drilling and production technology, is

addressing one of the topic road maps related to reservoir

geochemistry, which contributes to the understanding

of the hydrocarbon sources, affects the basin modeling

and understanding of the big picture, and helps with

production allocation.

In the memorandum of understanding signed in

October 2013, Shell and KMG agreed to establish a center

of excellence on geochemical studies on the basis of the

upgraded facilities of CaspiMunaiGaz laboratory complex

in Atyrau that is due to be commissioned by the end of

the year.

The new laboratory complex will provide geochemical

services and research in exploration, development,

and production. The technology, particularly reservoir

geochemistry and geochemical fingerprinting, is very

important in understanding some of the major industry

problems in Kazakhstan, such as high water cut, decreasing

production, and relatively low recovery rate.

The introduction of the new technology and know-how

will allow KMG to improve field economics, extend the field’s

life, and maximize oil production with the least number of

wells and at minimum cost.

Planning and Strategy

Creating successful alliances of industry members is the

key to developing the full spectrum of technologies that

future markets will demand—only by working together

will challenges be converted into solutions.

In this context, it is important to establish a systematic

R&D planning process founded on the established principles

used to plan and manage R&D by many large technology-

oriented companies translated onto a national scale.

The process would drive the upgrade of R&D

facilities in Kazakhstan, identify appropriate demonstrator

projects and field trials, ensure that industry challenges and

requirements are understood, improve access to data, and

promote collaboration across the institutes of learning.

The technology solutions created by the collaboration

of academic institutes and the industry will allow

Kazakhstan to maximize the value of its oil and gas resources

and create strong local companies to deliver those solutions

at international standards of quality. JPT

Eni workers at the Kashagan field. Photo courtesy of NCOC.

A worker at the control panel at the main processing hub of

the Kashagan field. Photo courtesy of NCOC.


Could you give us some details about your company?

KazMunaiGas Exploration & Production (KMG E&P), a subsid-

iary of Kazakhstan’s National Company KazMunayGas, was

established in March 2004 and runs onshore operations. At

the end of 2013, KMG E&P was ranked among the top three oil

producers in Kazakhstan. In consolidated volumes, KMG E&P

has around 15% market share of oil production in Kazakh-

stan, and around 4% of consolidated proved reserves. KMG

E&P’s shares are listed on the Kazakhstan Stock Exchange

and the global depository receipts are listed on the London

Stock Exchange. There are 70 fields, including acquisitions,

in KMG E&P’s portfolio. The largest field is Uzen, which began

development in 1965.

What are the major projects you are currently involved in?

One of our key current projects is our production

modernization program. This was announced in 2012, with

a targeted investment in the region of USD 350 million to

USD 450 million during the period 2012 to 2018. The program

includes the modernization of equipment, the construction

of new production facilities, the implementation of innovative

methods of enhanced oil recovery, and well servicing.

The fields in our portfolio are between 10 and 100

years old. Nevertheless, we are confident that while mature,

our assets still have potential. New methods, which have

only become available recently, will help develop these

mature assets for a significant duration.

KMG E&P has been implementing targeted

exploration to renew and increase its resource base.

This process has been going smoothly. The discovery of

a new deposit on Fyodorovsky block has resulted from

these efforts and is evidence of the high potential of

this asset.

What is the current production capacity of the fields you

operate in this region? What are their combined proved and

probable reserves?

We expect a gradual increase in the production volumes of

our core assets, namely Uzenmunaigas and Embamunaigas,

by 2018. KMG E&P assessed the economic feasibility

of the wells in order to arrive at an optimum production

level that ensures production from these wells is

still profitable.

KMG E&P’s production volume in 2013, including its

share in joint ventures, was 12.4 million tons (251,000 B/D).

The volume of consolidated proved and probable reserves

including its share in joint ventures, was 200 million tons

(1.5 billion bbl) at the end of 2013.

What are the regional key opportunities for your company

in the country?

Currently, we see very limited merger and acquisition

opportunities in the Kazakhstan oil and gas industry as

strategic players, such as international oil and gas companies

and consortiums, have been developing large onshore assets.

Today, the promising onshore assets are exploration

projects with the potential to discover hydrocarbons in deep

subsalt horizons. However, it is important to be mindful that

onshore subsalt horizons require thorough and extensive

study, due to the high exploration risks, and even if the

results of exploration are positive, commercial production will

not be achieved for some time thereafter. The same applies

to offshore projects in the Caspian Sea.

Nevertheless, we regularly assess production and

exploration assets for potential opportunities and to maintain

the reserves increment.

What is the E&P strategy of your company?

We believe that investment into exploration must remain

under constant review and we recently revised our

exploration program for the next 5 years. Our analysis showed

that several blocks within the current exploration portfolio

had low potential and we therefore came to the conclusion

that there was no merit in further investment. Nevertheless,

unrisked prospective resources for the remaining blocks

are still around 200 million bbl. We remain committed to

investing up to USD 300 million annually, dependent on the

availability of new, promising exploration blocks.

KAZMUNAIGAS E&P

LOCAL MOTION Abat Nurseitov, chief executive officer of KazMunaiGas

Exploration Production JSC, highlights the operations of

his company and Kazakhstan and says the era of easy

oil is over.



Are you involved in any unconventional projects?

We are involved in conventional oil production projects

only; however, we are closely monitoring international oil

companies’ experience and technology in this area. We are

aware that the era of easy-to-recover oil is coming to an end

and that we need to continue to develop our own experience

in unconventional hydrocarbon production to ensure we

remain competitive.

Are you using any particular technologies in the fields that

you operate?

To stimulate oil production, KMG EP has been implementing

enhanced oil recovery methods, hydraulic fracturing, polymer

injection, electrical treatment of oil reservoirs, as well as

a range of measures to treat bottomhole zones, such as

cement squeezing, reperforation, additional perforation,

acid treatment, and other types of treatment. Optimizing the

production process includes improving development plans and

adopting more effective monitoring of wells. These measures

enable us to maintain the optimum level of production at our

own fields, most of which are mature.

What are the challenges facing the operations of your

company in this part of the world?

KMG EP’s main fields are mature, with most of the easily

recoverable hydrocarbons recovered.

Currently, the majority of hydrocarbon reserves

are being extracted from hard-to-reach deposits due to

the lower porosity and permeability properties of these

deposits. Extraction of hydrocarbons requires significant

investment in research and the implementation of

proper technology.

It is well known that the era of “cherry picking” from

good reservoirs at shallow depths is coming to an end. The

probability of such deposits being discovered is very low

given the present degree of exploration and, therefore, the

search for new deposits requires the implementation of new

exploration approaches, methods, and technologies. Poorly

explored subsalt Paleozoic structures are the most promising;

however, their exploration is associated with high levels

of geological risk and deep, complicated drilling requiring

extensive investment.

In addition, in view of our long-term plans, KMG E&P is

conducting an analysis of geological data from across the

various regions of Kazakhstan, which have not historically

been considered as petroleum-bearing.

The energy industry is likely to become more capital

intensive and increasingly focused on long-term projects than

it has in the past. We also believe that there are significant

opportunities in Kazakhstan for further exploration of black

gold and blue flame gas resources, and anticipate that new

discoveries will be made. JPT

The processing facility at Tengiz. Photo courtesy of Lukoil.


The Kashagan field is an offshore oil field in Kazakhstan’s

zone of the Caspian Sea. Discovered in 2000 and named

after a 19th-century Kazakh poet from Mangystau, the

field is considered the world’s largest discovery in the past 30

years, combined with the Tengiz field.

Located 80 km off the coast of Kazakhstan near Atyrau,

the Kashagan site lies in the northern area of the Caspian

Sea. Water depths range from 2 m to 6 m, and temperatures

fluctuate between -40°C and 40°C in a year.

Kashagan is the most important field in the 11 blocks

falling under the North Caspian Sea Production Sharing

Agreement (NCSPSA), covering a total of 5600 km² in the

Kazakhstan part of the Caspian Sea. Other fields falling

under the same PSA are Kashagan South West, Aktote,

Kairan, and Kalamkas. This PSA was concluded between the

government of Kazakhstan and the Offshore Kazakhstan

International Operating Company (OKIOC) in November 1997.

At the time, the consortium committed to invest USD 7 billion

in the project to start oil production in 2005, and to build

a pipeline for oil export before 2013, which would have to

accommodate the planned production volume of 30 million

tons per year.

Background

The story of the field dates back to early 1992, when an

exploration program announced by the Kazakh government

sought the interest of more than 30 companies to partake

in the exploration. In 1993, the Kazakhstan Caspian shelf

was formed, which consisted of Eni, BG Group, BP/Statoil,

ExxonMobil, Royal Dutch Shell, and Total, along with the

Kazakh government. This consortium lasted 4 years until

1997, when seismic exploration of the Caspian Sea began.

Upon completion of an initial 2D seismic survey in

1997, the company became known as OKIOC. In 1998, Phillips

Petroleum Company and Inpex joined the consortium.

In May 2000, first oil was found at Kashagan with initial

estimates suggesting an oil field with reserves of no less

than 11 billion bbl. The Kazakh government said the reservoir

The Mystery of Kashagan


The manmade islands are home to Kazakhstan’s mammoth Kashagan field. Photo courtesy of North Caspian Operating

Company (NCOC).


at Kashagan was likely a continuation of the giant Tengiz oil

field on the east coast of the Caspian Sea. But in July 2000,

Kazakhstan’s President Nursultan Nazarbayev said the field

could hold at least 50 billion bbl of crude. “Today, I can tell you

that this is the largest recently discovered field in the world,”

he said.

The consortium changed when it was decided that

one company was to operate the field instead of a joint

operatorship as agreed upon. Eni was named the exclusive

operator in 2001. In the same year, BP/Statoil sold its stake

in the project to the remaining partners. The project was

renamed Agip Kazakhstan North Caspian Operating Company

NV (Agip KCO).

In 2003, BG Group attempted to sell its stake in the

project to two Chinese companies, China National Offshore

Oil Corporation (CNPC) and Sinopec. However, the deal did

not go through because of the partners’ exercise of their

pre-emptive privileges. Eventually, in 2004, the Kazakh

government bought half of BG’s stake in the contract, with

the other half shared among the other Western partners in

the consortium that had exercised their pre-emptive rights.

The sale was worth approximately USD 1.2 billion. The Kazakh

stake was transferred to the state-owned oil company

KazMunayGas. On 27 September 2007, the Parliament of

Kazakhstan approved a law enabling the government to alter

or cancel contracts with foreign oil companies if their actions

were threatening national interests.

KazMunayGas further increased its stake in January

2008, after its partners and the Kazakh government agreed

on compensation for the probable 5-year delay that was

taken in developing the field. Eni operated the project under

the joint venture company name of Agip KCO. Following the

agreements reached on 31 October 2008 between Kazakh

authorities and co-venturers under the NCSPSA, operatorship

of the NCSPSA was formally transferred from Agip KCO to a

new company, North Caspian Operating Company (NCOC), on

23 January 2009.

In October 2008, Agip KCO handed a USD 31 million

letter of intent for front-end engineering design work

on Phase 2 of a joint venture involving Aker Solutions,

WorleyParsons, and CB&I. WorleyParsons and Aker Solutions

are also engaged in Phase 1, carrying out engineering

services, fabrication, and hookup.

In November 2012, Oil and National Gas Corporation

Videsh agreed to buy ConocoPhillips’ 8.4% stake. The Kazakh

government, however, decided in July 2013 to use its pre-

emptive right to buy ConocoPhillips’ stake, which it sold to

CNPC later that year.

In August 2013, KazMunayGaz agreed to sell an

8.33% stake in Kashagan to CNPC, leaving the Kazakh

company with a slightly higher shareholding than before

of 16.88%.

Field’s Geology

The field is a carbonate platform of the Late Devonian

to Middle Carboniferous age. The reef is about 75 km long

and 35 km wide, with a narrow neck joining two broader

platforms, Kashagan East and Kashagan West.

The top of the reservoir is 4.5 km below sea level and

the oil column extends for more than 1 km. The seal is Middle

Permian shale and Late Permian salt.

The reservoir consists of limestone with low porosities

and permeability. The oil is light, with 45 °API gravity with a

high gas/oil ratio and a very high H2S content of 19%. The

field is heavily overpressured, which presents a significant

drilling challenge.

The figures for oil in place range between 30 billion

bbl and 50 billion bbl with a common publicly quoted

An aerial view shows the artificial islands at the Kashagan oil field in the Caspian Sea offshore Kazakhstan. Photo courtesy

of NCOC.

KASHAGAN FIELD


figure of 38 billion bbl, but because of the reservoir’s

complexity, the recovery factor is considered relatively low,

approximately 15% to 25%.

The Caspian Sea is 30 m below sea level. Most of its

mean water depth is 208 m, although the northeast area is

considerably shallower. Temperatures can fall below -40°C in

winter and a coating of ice, several meters thick, forms in this

part of the Caspian Sea for many months.

Discovery well Kashagan East 1 was a single vertical

well that was drilled to a total depth of 5200 m in 2000.

During tests, the well flowed at a rate of 600 m³ of oil and

200,000 m³/d of gas on a 32/64-in. choke.

Kashagan West 1 was the second discovery well.

Drilled in 2001, tests showed that the well flowed at a rate of

3,400 BOPD, while the oil gravity measured between 42 °API

and 45 °API.

Kashagan East 2 was drilled in late 2001 to a depth of

4142 m and flowed at a rate of 7,400 BOPD.

Challenging project

As well as being one of the largest projects in oil history

outside the Middle East, the Kashagan has proved to be one

of the most complex. It combines an unprecedented array

of characteristics that demand unique technological and

logistical solutions.

The Kashagan project has a very high technical

complexity due to natural circumstances. The climate is

extreme continental with cold winters, hot summers, and

drastic variations of temperature.

The waters in the northern part of the Caspian Sea are

frozen for 4 to 5 months, from November to March, and the

ice thickness averages about 0.6 m to 0.7 m. The combination

of ice, shallow water, and sea level fluctuations represents a

significant logistical challenge.

Because of the environmental conditions, icebreaking

supply boats are used. Most icebreakers work by using the

weight of the ship to crack the ice, but this does not work

in the shallow waters of the Caspian, so shallow-draught

Arcticaborg icebreakers from Finland’s Kvaerner Masa

shipyards were brought in to break the ice, using specially

designed propellers. Special tugs were also designed

to work in these waters, and arrived in the Caspian in

September 2002.

Other technological challenges include reservoir

depth of 5000 m; high reservoir pressure at –800 bar; high

hydrogen sulphide (H2S) content (16% to 20%); management

of byproducts such as sulfur; and the use of sour gas

reinjection into the reservoir.

Appraisal drilling was started in May 2001 at Kashagan

East using the 6,000-ton ice-resistant Sunkar barge. The

first appraisal well was completed in mid-2000 and was

followed by another at Kashagan West, located approximately

40 km apart, and was completed early the following year.

Both wells were successful with production estimated at up

to 20,000 BOPD of 42 °API to 45 °API oil, at a high pressure,

high gas/oil ratio, and a H2S level between 18% and 20%.

However, drilling the first well at Kashagan from the

Sunkar floating rig led to delays in production, so the OKIOC

consortium decided to develop an offshore complex of

artificial islands. It constructed a number of rock structures

that became known as “artificial” or “drilling” islands. In total,

four drilling islands, Island A and Island D for Kashagan and

two separate islands for Aktote and Kairan, have been built.

The four islands, together with a number of other

islands, were linked to onshore operations by pipelines. The

islands are also used to collect and store oil and ensure the

initial separation of oil and gas.

Another of Kashagan’s major challenges is the presence

of highly toxic and corrosive H2S in the associated natural

gas. With H2S concentrations of 18% to 20% by volume

emanating from Kashagan’s wells, the field will produce sour

gas with one of the highest levels of H2S encountered in the

offshore industry.

According to Agip, since production would reach 14

million MTPA of oil, it would entail the largest amount of H2S

gas to be reinjected into high-pressure reservoirs offshore in

order to avoid massive sulfur production and gas flaring. To

force the gas back into the reservoir, discharge pressures of

up to 760 bar are required, the highest pressures demanded

to date by a gas reinjection project in the industry.

According to a report by the European Union citing

Russian and Kazakh scientists, including professor Muftach

Diarov, the director of the Scientific Centre of Regional

Ecological Problems at the Atyrau Institute of Oil and Gas, the

extraction of oil under the huge pressure from subsalt wells,

in addition to reinjection of gas, amplify the potential

KMG

Eni

Shell

ExxonMobil

Total

CNPC

Inpex

16.807%

16.807% 16.807%

16.807%

16.807%

8.333%

7.563%

Fig. 1—Shareholders of the North Caspian Operating

Company.

JUMP TO PAGE 22


What are your major operations in Kazakhstan?

Eni started its activity in Kazakhstan in the early 1990s and is

currently involved in the development of the two major oil and

gas fields in Kazakhstan: Karachaganak and Kashagan.

Karachaganak is a giant gas condensate field, which has been

in production since the Soviet era. In 2004, Karachaganak

Petroleum Operating (KPO), a joint operating company

managed by Eni and BG, completed Phase 2 of development,

leading to the current production levels. Since then, a number

of drilling and facilities projects have been executed to

maintain and optimize the production plateau. Karachaganak

is currently working on the expansion project, soon to enter

the front-end engineering phase, which will further extend the

liquids plateau by increasing gas reinjection capacity.

The Kashagan field was discovered in 2000 and is

considered the biggest oil discovery worldwide in the past

40 years. Production from the first phase of development

started in September 2013, but was suspended because

of an unexpected problem with pipelines transporting the

sour gas and oil. The pipeline repair is ongoing and the

consortium partners are working in close cooperation

to restart production as quickly as possible without

compromising safety.

Kashagan represents an important asset for Eni

and will guarantee a stable contribution to our future

production. Since the earliest phases of the project, Eni has

put considerable effort into this development, contributing

particularly to human resources and know-how. This

contribution will continue into the future in cooperation with

the other partners of the North Caspian Sea Production

Sharing Agreement joint venture.


operate? What are combined proved/probable reserves?

Karachaganak is currently in production, with a capacity

exceeding 140 million BOE/yr. In terms of reserves, our assets

in Kazakhstan total approximately 12 billion BOE combined

proved/probable.

What future opportunities do you see for your company in

Kazakhstan?

In addition to the above mentioned projects, a key new

opportunity is associated with an agreement recently signed

with the state-owned oil and gas company, KazMunayGaz

(KMG). This agreement will give us access to 50% of the

exploration and production rights in Isatay, an offshore

exploration area located in the north Caspian Sea, which we

believe has significant oil potential. We are now preparing

for the exploration activities that will be carried out in

co-operatorship with KMG.

How would you describe your E&P strategy in Kazakhstan?

It is definitely a growth strategy. We have significant

investment plans for Karachaganak and Kashagan, as part of

our efforts to maximize the value of these world-class fields.

In addition, with a cooperation agreement signed in 2009,

we set the objective to expand our presence in the country

and to reinforce our cooperation with KazMunayGas. At that

time, we targeted offshore acreage in order to leverage our

valuable experience in carrying out exploration activities in the

environmentally and technically challenging Caspian Sea shelf.

The above mentioned agreement with KMG represents the first

visible result of this part of our growth strategy in Kazakhstan.

Are you involved in any unconventional projects around

the globe?

Eni has pursued a two-sided approach to unconventionals.

First, we entered into a North American shale gas joint venture

back in 2009 in order to gain hands-on experience with the

industrial practices for the development of these resources.

We have used the opportunity to evolve and demonstrate

the power of a series of technologies to optimize shale

development, from seismic to well logging, reducing well liquids

loading, network fluid dynamics optimization, and reservoir

simulation. We are currently pursuing opportunities in Ukraine

and China, as well as in Indonesia, which build on the know-how

forged in North America.

ENI

POWER OF TWO Daniele Bertorelli, executive vice president, Central Asia, Eni,

discusses the involvement of his company in the two major

oil fields in Kazakhstan, Karachaganak and Kashagan, and

outlines key opportunities for his company in the country.


ENI Q&A


Let me take a moment, though, to tell the other side

of the story. In the past decade, many international oil

companies made major investments in North American

unconventionals. Our view was that the world still offered

exciting opportunities in conventional oil and gas, both in

frontier and mature basins. We, therefore, geared up our

oil and gas exploration activity just as others were betting

heavily on unconventionals, and since then, we have made

two industry-leading discoveries: Perla, offshore Venezuela,

and Area 4 offshore Mozambique.

What key technologies or technology applications are you

using in your operations?

Eni has developed and continues to develop a technological

tool box containing industry-leading seismic and drilling

technologies, operations best practices, environmental

monitoring, and proprietary gas valorization technologies.

As we develop new technologies, we always keep in mind two

main requirements: practical focus and rapid deployment in

our operations. Seismic is a clear example of this, where we

have rapidly transferred powerful new imaging tools into our

standard exploration workflow, and with great impact.

In the Caspian region, we bring 60 years of experience

in exploring for and developing carbonates reservoirs. In

Karachaganak, with our co-operator BG, we have tested and

then aggressively deployed horizontal wells with multistage

completions in the high pressure and sour conditions of the

reservoir, and multistage acid fracturing (up to 10 stages).

We have also achieved an industry first in reinjection of

sour gas in Karachaganak, and will do so again in the future

at Kashagan.

How would you describe the relation between your company

and national oil companies in Kazakhstan?

Let me reply by recalling what Eni’s first chairman, Enrico

Mattei, said in 1957: “It’s their oil.” His belief was that energy

resources belong first and foremost to the oil-producing

countries and that the most profitable arrangements arise

out of the shared interests of all the actors involved. These

principles are one of our company’s most profound legacies, as

we can see from a perspective of 50 years.

Here in Kazakhstan, Eni has expressed this philosophy

also by developing a solid cooperation with KMG. The

recent agreement, again, clearly shows the results of this

approach and we are looking forward to the establishment

with KMG of two project companies, one for the joint

management of the operations of the Isatay offshore block

and another for the development of a shipyard project in the

Mangystau region.


company in Kazakhstan?

There are three main factors that make our operations

in Kazakhstan very challenging compared with other

conventional locations:

◗ Climatic conditions. The offshore north Caspian

freezes in winter because of arctic temperatures,

which can fall lower than -30°C combined with low

water levels and low salinity. The low water levels

also create difficulties in summer when high winds

from the east can lower the water level by up to 1 m,

creating difficult conditions for conducting marine

logistics operations. The temperature variation of

-35°C to 40°C also represents a challenge to overcome

both during the design stage and the execution

phase of projects, where it can impact construction

productivity quite noticeably.

◗ Complex technology. The reservoirs in our assets

are at high pressure and contain lethal levels of H2S,

with up to 16% in Kashagan. The presence of H2S is

a constraint for simultaneous operations (drilling,

construction, production, and maintenance activities)

and thus affects productivity. The sour gas reinjection

pressures, ca. 750 bar for Kashagan, are also pushing

the technology boundaries of the industry. Also,

the republic is a landlocked nation, which requires

innovative solutions to bring process modules into the

Caspian through the canal system.

◗ Environmental sensitivity. The shallow-water areas of

the offshore north Caspian are classified as Special

Environmentally Restricted zones, also recognized

by UNESCO.

As co-operators of the onshore Karachaganak field and

partners in the North Caspian PSA, where we are involved in

both the onshore and offshore Kashagan operations, we have

acquired a vast and unique firsthand experience in Kazakhstan

over the past 20 years. This gives us the confidence to face the

future challenges of these and our other initiatives. JPT

AZERBAIJAN ENERGIZED

AZERBAIJAN

AZERBAIJAN—AZERBAIJAN ENERGIZED


MALAYSIA—REACHING SKYWARD

The first oil well in the world was

drilled in Absheron, Bibi Heybat, in

1847 using a primitive percussion

drilling mechanism. It was not until

11 years later that the first oil well

in the United States was drilled in

Pennsylvania. The first oil refinery was

also built in Baku in 1878. This refinery

was connected to the Balakhani oil

fields via a newly constructed pipeline

12 km long. By the end of the 19th

century, Baku had become a center for

world-scale industrial investment.

In the time of the Russian Empire,

Baku was the main oil supplier, providing

97.7% of Russia’s oil in 1890 and half of

the world’s output in 1901. Following

its independence from the Soviet

Union in 1991, Azerbaijan experienced

an economic recession, resulting in a

decline in oil production from 20 million

tons in 1970 to 10 million tons in 1995

as a result of a conflict with Armenia

over Nagorno-Karabakh, outdated

technology, poor planning, and lack

of investment in new drilling and

rehabilitation of existing wells.

Located within the South Caspian

basin, Azerbaijan is one of the Caspian

region’s most important strategic

export openings to the West. Oil and gas

development and export is central to its

economic growth.

Oil Production

Oil production in Azerbaijan increased

from 315,000 BOPD in 2002 to 1 million

BOPD in 2010. However, production

declined since then, falling to 932,000

BOPD in 2012. According to the 2014

BP Statistical Review of World Energy,

Azerbaijan’s oil reserves stand at

7 billion bbl of oil as of the end of 2013,

with production at 931,000 BOPD

during the same period. Most of the

potential oil is located offshore in the

Caspian Sea, particularly in the Azeri-

Chirag- Guneshli (ACG) fields, which

accounted for more than 80% of total

oil output in the country in 2012.

Similar to its share of total production,

ACG also holds the vast majority

of Azerbaijan’s total reserves, with

approximately 5 billion bbl located in

this field.

Located 120 km off the coast, ACG

is Azerbaijan’s largest oil field with oil

reserves estimated at 5.7 billion bbl.

The production sharing agreement

known as the “Contract of the Century”

was signed in 1994 for the development

of the field by 11 major oil companies,

called the Azerbaijan International

Operating Company (AIOC), and the

Azerbaijan government. The agreement

is valid for 30 years. The field was

originally operated by BP on behalf of

AIOC and total investment amounts

to about USD 20 billion. Later, some

companies sold their shares and the

last one, Devon Energy, announced the

sale to BP of its 5.62% shareholding in

ACG in 2010.

The ACG field was developed in three

main stages. The first stage started

with production from the Chirag

platform in 1997. The second stage

consisted of two phases: Phase I was

the development of Central Azeri in

2005, and Phase II was the development

of East Azeri in 2005 and the West Azeri

platforms in 2006. The third stage was

launched with the deepwater Guneshli

platform in 2008. Chirag provided

overall production of 105,300 BOPD

from its 19 wells in operation in 2009,

Central Azeri produced 185,800

BOPD from 18 wells in operation,

West Azeri produced 275,200 BOPD

from 18 wells in operation, East Azeri

produced 139,400 BOPD from 13 wells

in operation, and deepwater Guneshli

produced 116,400 BOPD from 17 wells

in operation (BP Sustainability Report,

2012). Most of the crude oil from ACG

is exported through the Baku–Tbilisi–

Ceyhan (BTC) pipeline and the rest

through the Baku-Supsa pipeline and

Baku-Novorossiysk pipelines.

According to the United States

Energy Information Administration

(EIA), production problems have

affected ACG output in the past

couple of years, with unexpected

production declines occurring

because of technical problems. A new

development, the Chirag Oil Project

(COP), plans to increase oil production

and recovery from the ACG field

through a new offshore facility. COP

was commissioned in early 2014, with

peak production capacity reaching

360,000 BOPD, according to BP.

In addition to the ACG output, a small

but stable volume of approximately

40,000 B/D of condensate is produced

at the BP-operated Shah Deniz field,

with further volumes produced by

the State Oil Company of Azerbaijan

Republic (SOCAR), mainly from the

shallow-water Guneshli field. The other

oil fields in Azerbaijan are the Ashrafi,

Bahar, Dan UIduzu, Darwin Bank,

Karabakh, Nakhchivan, and Shafag,

and Asiman.

SOCAR, which produces

approximately 20% of the country’s

output, is responsible for the

exploration and production of oil and

natural gas in Azerbaijan. It operates

Azerbaijan is among the oldest crude producers in the world and considered the birthplace of the oil industry. According to historical accounts, “the Baku fortress was surrounded by 500

wells, from which white and black acid refined oil was produced.”


PREVIOUS, Shah Deniz gas field is the

largest natural gas field in Azerbaijan.

Photo courtesy of Lukoil.



two refineries, runs the pipeline system,

and manages the oil and natural gas

imports and exports.

According to the EIA, Azerbaijan

produces three grades of crude oil: the

SOCAR-produced barrels, Azeri BTC,

and Azeri Light. The SOCAR-produced

crude oil is mainly refined domestically,

with only a small fraction available for

exports as domestic demand grows.

Because of its poor quality, the SOCAR-

produced crude oil is blended in Russia

and marketed as the Urals blend.

The country’s main export crude oil

streams are Azeri BTC and Azeri Light.

These two fairly similar grades are

mainly sold to the European and Asian

markets. Azeri BTC blend, named for

the BTC pipeline through which it is

exported, is made up of mostly Azeri

Light from the ACG field and the Shah

Deniz condensate, which has been

blended into the crude stream since

2007. Azeri Light is produced only from

the BP-operated ACG field, and it is a

medium-light, sweet crude oil (35 °API

gravity and 0.14% sulfur), very similar in

quality to Nigeria’s Bonny Light.

Rich in Gas

Azerbaijan’s proven gas reserves are

estimated at about 31 Tcf (0.9 Tcm),

according to the 2014 BP review. The

country produced 16.2 Bcm of natural

gas in 2013.

Azerigaz, a SOCAR subsidiary, is

responsible for natural gas processing,

transport, distribution, and storage,

mainly in the domestic market. Azneft,

another subsidiary, is responsible

for exploration, development, and

production from the older onshore

and offshore natural gas fields owned

directly by SOCAR. The state oil

company produced 7.3 Bcm of gas

in 2013.

Virtually all natural gas is produced

from offshore fields. After the country’s

independence, gas production declined

steadily to 4.5 Bcm in 2005, compared

with 8 Bcm in 1991. Azerbaijan

imported gas from Russia up to 2007 to

meet domestic consumption demand.

After increasing its own gas production,

Azerbaijan stopped buying gas from

Russia and instead became a gas

exporter in the region.

Almost all of Azerbaijan’s natural gas

is produced in two offshore fields: the

ACG complex and Shah Deniz. Other

major gas producing fields include the

Shafaq, Asiman, Umid, Nakhchivan,

Absheron, Dan Ulduzu, and Ashrafi.

The Shah Deniz natural gas and

condensate field started production

in late 2006, making Azerbaijan a net

gas exporter. Discovered in 1999, the

field is one of the world’s largest gas

and condensate fields. It is located on

the deepwater shelf of the Caspian Sea

in depths of up to 1,600 ft. According

to BP, the development’s operator,

the field has approximately 40 Tcf

of natural gas in place. It produced

approximately 346 MMcf/D of natural

gas and 53,740 B/D of condensate

in 2013.

The Shah Deniz Stage 1 development

includes a fixed offshore platform,

two subsea pipelines to bring the

hydrocarbons ashore, and an onshore

gas-processing terminal adjacent to

the oil terminal at Sangachal, near

Baku. According to BP, from 2006 to

2013, the Shah Deniz produced about

1.7 Tcf of natural gas and 100 million

bbl of condensate.

The Shah Deniz Stage 2, or Full Field

Development (FFD), will have a peak

capacity of 565 Bcf (in addition to the

315 Bcf in Phase 1), making it one of

the largest gas development projects

in the world, BP said. Operators expect

it to start producing in 2017 and supply

European markets with natural gas

in 2019. The development of Shah

Deniz FFD is currently in the front-

end engineering and design phase.

The transportation of gas from the

Caspian Sea to Europe will require an

enhancement of the existing pipelines

and development of new infrastructure.

“Shah Deniz Stage 2 is our next big

development. By 2018, we will build

two offshore platforms, install subsea

pipelines, drill subsea wells, expand the

terminal at Sangachal and complete

a new pipeline corridor to Europe,”

said Pat Draughon, vice president of

production for the Azerbaijan, Georgia,

and Turkey Region at BP, during the

Caspian Oil and Gas Conference held in

Baku in June.

From about 2019, the Shah Deniz

is expected to feed 16 Bcm/yr of gas

to Europe, with 10 Bcm earmarked for

Europe and 6 Bcm for Turkey. Half of

the gas is destined for Italy, a SOCAR

official said. “Around 8 Bcm of gas will

be shipped to the Italian market, where

European buyers will be getting it for

their facilities in Italy,” Elshad Nasirov, a

vice president of SOCAR, told reporters

earlier this year.

Partners in the Shah Deniz are

also drawing up plans for the third

development stage of the major

gas project after 2025, expecting

The offshore platform at Deepwater Guneshli complex is the third phase in the

development of the Azeri-Chirag-Guneshli field. Photo courtesy of BP.



to reach peak output at about

25 Bcm/yr of gas. “Shah Deniz

consortium partners have already

agreed on seismic works and

exploratory drilling under the third

stage of the Shah Deniz project,”

a SOCAR official told Reuters. “BP

had presented its own preliminary

estimations, according to which the

field may contain 1.7 Tcm of gas, up

from a current estimate of 1.2 Tcm.”

Wise Decision

When Azerbaijan launched the ACG and

BTC projects, they were considered

economically unviable in the untested

investment climate and low oil price

environment of the first decade of

Azerbaijan’s independence. Russia

and Iran considered the award to be in

breach of the Caspian legal conventions

and a threat to the Caspian marine

and geopolitical environments. But

the current market context appears

to vindicate the projects as a success.

“Aside from private shareholder

returns, ACG and BTC serve public

energy market diversification and anti-

monopoly goals in today’s high oil price

environment and, in bypassing the

Bosporus, also reduce environmental

and safety concerns,” according to a

report by the Clingendael International

Energy Program (CIEP), an affiliate

of the Netherlands Institute of

International Relations.

In their ramp-up stage, which

coincided with the commodity price

boom, ACG production and BTC exports

contributed a quarter of global oil

supply growth at a time when the

Caspian was believed to be able to

contribute 10% to world oil supplies

over the medium term, according to

an International Energy Agency report

in 2004.

Major investments in the exploitation

and development of new gas fields

in Azerbaijan may tremendously

increase the country’s estimated

gas reserves and enable it to meet

rising international demand for gas.

Gas imports in European countries

are expected to double by 2030,

and Azerbaijan’s gas reserves are

seen as the one of the primary

sources for meeting demand,

particularly from eastern and central

European states.

In September 2013, Azerbaijan

signed contracts to supply

European buyers with gas, offering

them an alternative supply source

to Russia toward the end of the

decade. SOCAR and its partners,

including BP and Statoil, selected

the Trans Adriatic Pipeline for

potential gas deliveries to Europe,

following more than a decade of

planning, dealing a blow to Russia’s

aspiration for tighter control over

gas routes. JPT


the gas cut-offs of 2006 and 2009, the policy’s focus shifted

to unlocking Caspian gas. Russia concluded various long-

term framework contracts with Turkmenistan and Uzbekistan

for gas deliveries to support security of supply, while Turkey,

the US, and the European Union sharpened their focus on

Azerbaijan and the wider Caspian to enhance engagement and

complement established Russian supplies to EU from Caspian

sources. Consequently, the so-called Southern Corridor became

a rallying point in the EU’s quest to improve the diversity of its

gas supplies.

Consequently, the considerable gas reserves of Turkmenistan

will serve newly emerging Asian markets.

The role of the operating companies and the prudential

management of hydrocarbon wealth in the Caspian Sea region,

are increasingly important topics. And discussions must now

begin within government in resource-rich countries with regard

to designing optimal energy policies.

Because of rapid changes in the oil and gas industry in

the Caspian region and the requirements to adapt to these

changes, local governments are working on reorganizing and

restructuring their energy sector to meet the new challenges,

and achieve the required objectives, with an ultimate goal to

be more effective in tackling the various challenges facing the

industry. In early August, Kazakhstan announced the creation of

a new, larger energy ministry and appointed Vladimir Shkolnik,

a two-time former energy minister, to head a new department

that combines the oil and gas ministry, the industry and

new technologies ministry, and the environmental protection

ministry. Former Oil and Gas Minister Uzakbai Karabalin now

serves as Shkolnik’s first deputy in the new ministry. JPT

JUMP FROM PAGE 3UNCOVERING THE CASPIAN—INTRODUCTION


What are your major projects in the Caspian Sea?

Lukoil has discovered eight oil and gas condensate fields

in the Caspian Sea, with seven of them in the north Caspi-

an. In 2010, the company commenced oil production at the

Yuri Korchagin field in the Russian part of the Caspian Sea.

Preparations for the second phase of the field's development

are ongoing.

Lukoil also expects to commission the Vladimir

Filanovsky offshore field soon. Jackets for the offshore

platforms were installed this year and subsea pipelines are

now nearing completion.

The phase-based program for integrated development

of the north Caspian fields implies the construction of 25

platforms with the total weight of about 100,000 tons.

Pipelines will run for more than 1500 km, including subsea

lines around 1000 km long.

In addition to the Russian part of the Caspian Sea,

Lukoil is very active in Azerbaijan and Kazakhstan. In

Azerbaijan, Lukoil started its operations in 1994, when it

acquired 10% share in the Azeri-Chirag-Guneshli project

to develop the largest field in the Azerbaijani area of the

Caspian (Lukoil is no longer part of that project). In 1996,

the company joined the project to develop the Shah Deniz

offshore gas condensate field.

In Kazakhstan, Lukoil has been operating since

1995. The company has since joined several onshore

production projects and the Caspian Pipeline Consortium

(CPC). Lukoil has become the largest Russian investor in

Kazakhstan’s economy, having invested over USD 7 billion.

The current share of the company’s production of crude

hydrocarbons is about 10% of Kazakhstan's total production.


operate in this region? What are their combined proved and

probable reserves?

As of the end of 2013, the Yuri Korchagin field held 121 million

BOE of proved reserves and produced 1.4 million ton/yr. The

Filanovsky field held 487 million BOE of proved reserves at the

end of 2013. The target production is 6.1 million ton/yr. Eight

multireservoir fields discovered by Lukoil in the Russian part

of the Caspian Sea boast 1.19 billion tons of oil equivalent of

C1 and C2 reserves altogether.

What are you doing in the region in relation to gas?

The associated gas produced at the Korchagin field will

be reinjected into the gas cap until 2016. This approach

allows us to avoid flaring and also improves oil recovery by

contributing to reservoir pressure. The gas produced at this

and other fields of the Caspian will be transported to Lukoil’s

onshore gas refinery and gas chemical plant when a gas

pipeline is operational.

What are your company's major accomplishments in terms of

upstream technology development in this part of the world?

What technologies are you using in the Caspian region?

Lukoil has been continuously testing and implementing new

high-performance technologies. For instance, one of the

commissioned wells at the Korchagin field is unique in terms

of construction: the horizontal section is 4300 m long with a

total wellbore length of 7600 m, which makes this well one of

the most complex in the history of drilling.

The company also utilizes lower completion

technologies in the north Caspian. The wells of the Korchagin

field are equipped with ResFlow passive flow control systems

to prevent gas breakthrough.

Lukoil proudly follows a zero discharge policy for all its

offshore projects with an absolute prohibition of any waste

release into the marine environment. Production waste is

collected in containers that are sealed and transported

ashore for decontamination and disposal. The zero discharge

policy is rigorously followed both during exploration and

development drilling and commercial production to ensure

that the environment remains clean.

How would you describe your company’s relations with

national oil companies in the Caspian region?

Close cooperation has been established with national

oil companies in a number of projects in the Caspian

LUKOIL OVERSEAS E&P

PRIVATE POWER Fedor Klimkin, manager, Lukoil Overseas, says his company

will continue to be a key player in the Kazakhstan oil and

gas industry as it produces about 10% of the country’s total

oil production.


LUKOIL Q&A


region. Lukoil participates in the development of the giant

offshore Shah Deniz field in Azerbaijan together with BP

and Statoil. The state-owned oil company Socar (State Oil

Company of Azerbaijan Republic) is the project partner on the

part of Azerbaijan. Commercial production of hydrocarbons at

Shah Deniz started in 2006. Last year, Lukoil’s share in

production of marketable hydrocarbons was 6 million BOE.

Implementation of the project's second phase started

in 2013.

Lukoil has also established a partnership with

KazMunaiGaz. Lukoil and KazMunaiGaz joined international

consortiums to develop two large onshore fields,

Karachaganak and Tengiz, in the western part of the country.

Lukoil Overseas, the company's subsidiary, is running these

projects as well as the rest of the Lukoil’s international

upstream projects.

The Karachaganak field development is one

of the earliest and most efficient projects of Lukoil

Overseas. The field is expected to reach maximum

oil production at a level of 12 million tons/yr by 2017

with maximum gas production expected to exceed

26 Bcm by 2028. Tengiz is the second largest field of

Kazakhstan in termsof oil reserves and is expected to

reach a maximum oil production level of 36 million tons/yr

by 2019.

What is the E&P strategy of your company in the Caspian?

The Caspian region is strategically important for Lukoil,

especially the north Caspian. That is why the company pays

special attention to the development of this region’s resource

potential. In 2013, follow-up exploration added 51 million BOE

to Lukoil’s proven reserves in the north Caspian. In recent

years, Lukoil has carried out comprehensive, wide-ranging

geological and geophysical surveys in the Russian part of the

Caspian Sea, so we can say that we have discovered a new oil

region for development.

Azerbaijani and Kazakh projects were among the

first in Lukoil’s international upstream portfolio, and we

are interested in further developing our business in these

countries. We target major hydrocarbon production capital

projects, including those involving partnerships with global oil

and gas leaders.

Could you outline the main opportunities for your company

in the Caspian region?

Lukoil is continuously monitoring and evaluating

opportunities for business development in the Caspian region.

Participation in major capital oil and gas projects should build

a foundation for a robust production center in this region and

support the company's further growth. Certainly, adequate

profitability for our shareholders will always be a key factor in

making decisions on joining new projects. JPT

threat for an ecological catastrophe because of the increased

potential for technogenic earthquakes.

Numerous Setbacks

According to an NCOC statement, the project started

production on 11 September 2013, but operations had

to be stopped on 24 September because of a gas leak in a

onshore section of a gas pipeline running from Island D to

the onshore processing facility at Bolashak.

The affected pipeline transports oil and gas from the

island to the facilities. Each of the pipelines is approximately

90 km long, 28 in. in diameter, and of a design specification

to be resistant to the water and H2S content found in the

Kashagan hydrocarbons. The pipeline’s pools were supplied

by two Japanese companies, Sumitomo and JFE, while the

Italian company Saipem was contracted for laying the pipes.

The field is likely to be delayed by 2 more years while

200 km of pipeline is being replaced.

Kazakhstan's ex-oil minister, Uzakbay Karabalin, said

during the June 2014 World Petroleum Congress that his

country will have to “grin and bear” the continued delays

at the field, with the full-scale project not beginning until

2016. Karabalin said that multiple delays at the field have

had a “significant impact” on its economy, but they would

not bring down the its economy or oil industry. “There are

clusters of delays that need to be resolved,” he said. “All

challenges got concentrated. Last year, we were happy,

really happy with how the wells were performing normally,”

he said at the conference. “But when it comes to a very

small telemetric object—the pipe—it turns out to be a

complicated problem. We just have to grin and bear it, and

keep working hard.”JPT

JUMP FROM PAGE 14KASHAGAN FIELD

GAS FOR CASH

TURKMENISTAN

TURKMENISTAN—GAS FOR CASH


INDONESIA—REVIVING AMBITIONS

Turkmenistan has substantial

reserves of oil and gas and

geologists have estimated that

99.5% of its territory is conducive to

prospecting. Oil and gas is the backbone

industry of Turkmenistan economy as

it holds a huge natural gas reserve of

17.5 Tcm and 600 million bbl of proved

crude oil reserves, according to the

2014 BP Statistical Review of World

Energy. The country is the second largest

dry natural gas producer in Eurasia,

behind Russia.

Major Oil Fields

Most of Turkmenistan’s oil fields are

situated in the South Caspian basin

and the Garashyzlyk onshore area in

the west. In addition, its claim of the

Caspian Sea contains 80.6 billion bbl

of oil, though much of this territory

is unexplored.

According to the United States

Energy Information Administration,

oil deposits are located in disputed

areas of the Caspian Sea, and without

an agreement among Iran, Azerbaijan,

and Turkmenistan on maritime

boundaries, these fields may remain

undeveloped. The disputed Kyapaz-

Serdar oil and gas field linking the

Turkmenian and Azerbaijani maritime

border in the Caspian Sea holds between

367 million bbl and 700 million bbl of

recoverable reserves. Turkmenistan

sought an international arbitration

to settle its boundary dispute with

Azerbaijan in 2009; this issue and its

claims to portions of the Azeri and Chirag

fields being developed by its neighbor are

still unresolved.

Most of Turkmenistan’s oil is extracted

by the Turkmenistan State Company

(Concern) Turkmennebit (also known

as Turkmenoil or Turkmenneft) from

fields at Koturdepe, Nebit Dag, and

Cheleken near the Caspian Sea, which

have a combined estimated reserve of

700 million bbl of proved crude oil. The

oil extraction industry started with the

exploitation of the fields in Cheleken

in 1909 and Nebit Dag in the 1930s,

and production leaped ahead with the

discovery of the Kumdag field in 1948

and the Koturdepe field in 1959.

Turkmenistan’s oil production has

increased from 110,000 BOPD in 1992

to approximately 202,000 BOPD in 2010.

Production reached 231,000 BOPD in

2013, according to the BP Statistical

Review. Short-term forecasts keep

production relatively flat through this

year. About half of the production is

slated for the domestic market that

consumed slightly more than 130,000

BOPD last year.

According to officials, Turkmenistan

aims to produce more than 1.3 million

BOPD from offshore and onshore oil

fields by 2030; however, other industry

sources forecast that the production

will be less than 300,000 BOPD in the

same period.

Most of the production growth in

recent years came from Dragon Oil’s

offshore block, Cheleken, and Eni’s Nebit

Dag field in the onshore western area.

The UAE’s Dragon Oil currently

produces 73,750 BOPD, mainly from the

Cheleken Contract Area, and anticipates

increasing its output in the country to

100,000 BOPD by 2015.

Turkmenistan has also launched an

exploration campaign in a number of

areas across the country, including

Kemer Miesser, Simler, Shayyrdy, Akeser,

Garadashli, and West Korpedje, which

remains the main oil-producing region

of the country. In the campaign, 160

deposits were explored and 60 are now

under development.

As part of the ongoing exploration

activities, oil production was launched

for the first time in the Karakum Desert

from the Yylakly field. In addition, a new

oil field was discovered in the Altyguyi

region, which was previously considered

solely a gas-producing area.

Turkmennebit is also boosting its

production capacity of existing fields,

such as the Nebit Dag, Barsagelmes,

Gumdag, and Cheleken fields.

A recent report by Turkmenneft stated

that the company accelerated its drilling

operations last year and commissioned

82 wells. Local media said the

Korpedzhe drilling operation department

commissioned 18 wells into operation,

which is two times more than planned

and the above-target excavation of the

wells amounted to more than 27 000 m.

“The achievement in the Gogerendag

field in the Balkan region was significant

as well. The well No. 89 with a design

depth of 3650 m was commissioned at

the end of 2013, and drilling of the well

No. 37 with a design depth of 3950 m will

continue this year,” the company said.

Turkmenistan currently limits

investment opportunities for

international companies to offshore

oil and gas developments, with the

exception of production sharing

agreements (PSAs) with China vis-à-

vis the Bagtyiarlyk onshore natural gas

project in the southeastern region. In

2009, the Turkmenistan government

signed several PSAs with foreign

companies, including Russia’s Itera and

Turkmenistan has tremendous gas reserves, but hurdles on the foreign investment front are keeping

the country’s development plans in limbo.


PREVIOUS, Dragon Oil’s Dzheitune

(Lam) platform is part of the Cheleken

Contract Area in Turkmenistan. Photo

courtesy of Dragon Oil.


TURKMENSTAN—GAS FOR CASH

Germany’s RWE Dea, for offshore field

development in the Caspian Sea.

Rich in Gas

The gas-rich, geographically isolated

republic has announced plans to

boost its gas output to 230 Bcm by

2030 and annually export 180 Bcm

of the production. At the same time,

Turkmenistan is seeking ways to

release the current shut-in gas volume

by diversifying its portfolio of export

markets. The country anticipates an

increasing production as exports via

new pipelines to China and Iran ramp up.

Turkmenistan has several of the

world’s largest gas fields, including

10 with more than 3.5 Tcf of reserves

located primarily in the Amu Darya basin

in the southeast, the Murgab basin, and

the South Caspian basin in the west.

Recent major discoveries at South

Yolotan in the prolific eastern part of

the country are expected to offset most

declines in other large, mature gas fields

and will likely add to the current proved

reserve amounts. The South Yolotan-

Osman field is believed to contain

reserves with a low estimate of 4 Tcm,

a best estimate of 6 Tcm, and a high

estimate of 14 Tcm.

Located in the Amu Darya basin,

the Dauletabad field is one of

Turkmenistan’s largest and oldest

gas-producing fields with estimated

reserves of 60 Tcf. The field produced

approximately 1.2 Tcf in 2010 or most

of the country’s gas supply; however,

the production is declining.

China National Petroleum Corporation

(CNPC) is the only foreign company

with direct access to an onshore

development, the Bagtyiarlyk project

near the Amu Darya River, through a

35-year PSA. The project came on line

at the end of 2009 with a capacity of

182 Bcf/yr and began feeding gas to the

Central Asia-China pipeline. In 2012, the

field ramped up production capacity to

460 Bcf/yr to supply gas to China.

The Galkynysh field located in

Turkmenistan’s Mary province is

considered the second largest deposit in

the world, with reserves stands between

13.1 Tcm and 21.1 Tcm of gas estimated

by independent auditors, Gaffney, Cline &

Associates. The opening of the Galkynysh

gas field significantly increased the

total proved reserves and potential

hydrocarbon resources of Turkmenistan.

The giant Galkynysh field will serve as

the major source of the country’s future

gas export, Head of the Turkmengaz

State Concern Charymuhamet

Hommadov said at the International

Turkmenistan Gas Congress (TGC) held

in Avaza, Turkmenistan, in May. “One of

the major projects implemented in this

field is the industrial development of the

largest Galkynysh gas field, which will

serve as a major source of future export

pipelines,” he said.

Also known as South Iolotan, the

Galkynysh field has been developed under

a service contract by CNPC, Dubai-based

Gulf Oil & Gas, London-listed Petrofac,

and a South Korean consortium of LG

International Corporation and Hyundai

Engineering Company.

In September last year, the first stage

of the field development was completed

and a complex of facilities with a

capacity of 30 Bcm/yr of marketable gas

was put into operation. The second stage

of the field’s development started in May.

Hommadov also noted that with

the accomplishment of the second

stage, the total capacity of the field’s

facilities will amount to 60 Bcm/yr of

marketable gas.

Because most of the gas available for

future development is high in hydrogen

sulfide and carbon dioxide and has a

greater pressure and temperature,

these factors pose technical challenges,

thereby requiring greater capital costs

for exploration and development.

Douglas Uchikura, president of

Chevron Nebitgaz, told Reuters that

Turkmenistan requires tens of billions of

dollars to triple its natural gas output by

2030. “It would seem that Turkmenistan

would welcome long-term, large-scale

foreign direct investment in light of what

could otherwise become a daunting, if

not impossible, task,” he said.

Turkmenistan, a central Asian

nation of 5.5 million people, seldom

publishes data for its gas production and

exports. On the sidelines of the TGC, a

government official said the country is

aiming to increase its gas output from

70 Bcm in 2013 to 75 Bcm this year.

The effect of the commencement of

production at Galkynysh will become

evident by the end of the year, when

An offshore platform in the Cheleken Contract Area, which comprises two oil and

gas fields, Dzheitune (Lam) and Dzhygalybeg (Zhdanov), offshore Turkmenistan.

Photo courtesy of Dragon Oil.

TURKMENISTAN—GAS FOR CASH


INDONESIA—REVIVING AMBITIONS

the field is expected to reach peak

output. Once Line D of the Central

Asia-China gas pipeline is inaugurated

in 2016, Turkmenistan will be able to

increase substantially its exports to

China. It exported 20 Bcm of gas to

China in 2012, which is set to rise to

65 Bcm in 2020, equivalent to half of

China’s total gas consumption in 2011.

Currently, more than half of China’s

total natural gas imports are supplied

by Turkmenistan, and this proportion

will increase as more Turkmen-Chinese

export routes become available.

The announcement that the China

Development Bank will provide

financing to Turkmenistan’s state-

owned energy company, Turkmengaz,

for the second stage of development

at Galkynysh will ensure the attraction

of sizable foreign direct investment

from China in the foreseeable future.

Chinese firms, particularly CNPC, will

provide technological know-how to

the development. The field will also

have feed-through benefits to other

areas of the economy, in particular the

construction sector.

More Investments Needed

Oil production from Turkmenistan

has increased gradually since 2007

and is highly dependent on new

investment and technological capacity

to bring new fields on stream, and

resolving the Caspian Sea maritime

boundary disputes.

International oil companies (IOCs)

can participate in joint ventures or

PSAs with Turkmenneft for offshore

oil and gas blocks in the Caspian

Sea. Turkmenistan limits investment

opportunities for IOCs to offshore

oil and gas developments, with the

exception of the PSA with China on the

Bagtyiarlyk onshore gas project.

In April 2012, RWE Dea began

seismic acquisition program off the

Turkmenian coast in the Caspian Sea.

This enabled the company to explore

geological structures in the Miocene

and Pliocene at depths from 9,843 ft

to 21,325 ft (3000 m to 6500 m). The

seismic survey comprises the acquisition

of 3D data in an area of 154 sq miles

(400 km2) and a 2D program to assess

the further exploration potential of

Block 23. The survey took place in

shallow water, mostly less than 5 m

deep, where ocean bottom cables with

dual-sensor receivers (hydrophone

and geophone) were deployed on

the seafloor.

The oil and gas industry in

Turkmenistan faces several challenges.

The lack of sufficient foreign investment,

geographical challenges, inadequate

export pipeline infrastructure, and a rigid

economic structure are factors that have

deterred the country from becoming a

major hydrocarbon exporter.

Seeking New Markets

Already producing approximately

70 Bcm/yr of gas for export to Chinese,

Russian, Iranian, and central Asian

markets, Turkmenistan is becoming an

alternative to Russian gas for Europe.

A proposal to build the Trans-

Caspian Gas Pipeline would bypass

both Russia and Iran to carry Turkmen

gas across the Caspian Sea to

Azerbaijan and connect with pipelines

en route to Europe. This proposed

1,060-Bcf pipeline could connect to

the South Caucasus pipeline flowing

gas to Turkey and then to the planned

Nabucco pipeline to southeastern

Europe. Disputes over the Caspian

seabed jurisdiction between

Turkmenistan and Azerbaijan could

complicate the project’s viability.

Another way for Caspian region

exporters to meet the Asian energy

demand would be to pipe oil and

natural gas through Iran to the Arabian

Gulf or southwest to Afghanistan.

The Afghanistan option, which

Turkmenistan has been promoting,

would entail building pipelines across

Afghan territory to reach markets in

Pakistan and possibly India.

The Trans-Afghanistan Pipeline,

also called the Turkmenistan-

Afghanistan-Pakistan-India pipeline,

would span over 1,000 miles from

a point in Turkmenistan to Fazilka,

India, on the Pakistan-India border

and have a proposed capacity of

more than 1,200 Bcf/yr. Local

media suggested that the major

issues holding up construction

are supply security concerns,

uncertainty of pricing and fees,

and lack of financial commitments.

India and Pakistan suggested

paying below market prices, and

finalization of the sales and purchase

agreements presents a challenge to

the negotiations. JPT

The Dzheitune (Lam) Block-1 offshore platform, old and new, in Turkmenistan.

Photo courtesy of Dragon Oil.


What are the major projects that your company is involved in in the Caspian region? MOL Group has a diversified Caspian region portfolio with sizable reserves that we intend to bring on stream in the midterm to long term. An intensive field development program is under way in our Russian blocks, which will serve as the basis of mid-term production growth. Russia is a very important country within the group’s portfolio and carries significant potential. Currently, our Russian assets are the third highest contributors to our group-level production after Hungary and Croatia. We plan production growth in the midterm.

The MOL Group also has interests in two blocks in Kazakhstan. In the Fedorovsky block, MOL with its partners made significant discoveries in 2008 and 2009 with two successful exploration wells that proved commercial gas and condensate reservoirs in the Rozhkovsky field structure. In 2012, MOL acquired a 49% nonoperated interest in the high-risk, high-reward North Karpovsky block in west Kazakhstan. Since 2006, 1027 km of 2D and 300 km2 of 3D seismic have been acquired in the area. This extensive seismic program has proved the existence of multiple prospects.

Most recently, MOL, together with its partners, has successfully well-tested a new discovery in a shallow carbonate reservoir (Bashkirian) in the Rozhkovsky structure. Despite the small choke, we achieved just under 2,000 BOPD of high-quality light oil inflow as well as 6 MMcf/D of gas. This Bashkirian discovery confirms the presence of an additional working oil play within the Fedorovsky block and significantly increases the field's reserve prospects.

What is the current production capacity of the fields you operate in this region? What are their combined proved and probable reserves?MOL Group’s working share of 2P reserve size in the Caspian region is 132 million BOE and the average daily production is 6,500 BOPD.

In Russia, MOL operates the Baitugan field (51% stake) and several smaller fields in the Matjushkinsky block (100% stake). The Baitugan field has a 2P reserve size of around 110 million bbl of oil with 7,000 BOPD in production while the currently booked reserve size in Matjushkinsky area, which is still under exploration, has around 20 million bbl reserves today with 3,000 BOPD in production. Fifty producer and injector wells are being drilled this year to extend production to 10,000 BOEPD level by the end of 2014. The Yerilkinsky block, attained in 2012, is located a short distance to the northwest of the Baitugan field, and provides exploration upside in the coming years.

In Kazakhstan, initial production for MOL will commence with the Rozhkovsky gas-condensate field on the Fedorovsky block (27.5% stake). The field will commence production in 2016 with an estimated initial 15,000 BOEPD production. The 2P reserve size of the Rozhkovsky field is now estimated to be 220 million BOE, with a maximum predicted daily production potential of up to 45,000 BOEPD. The rapid appraisal and early development of the recent Bashkirian discovery will deliver additional production and reserves. We are continuing with exploration on the Fedorovsky block as well on the North Karpovsky block (49% stake), where approximately 200 million BOE hydrocarbon potential is being targeted.

Could you outline the key opportunities for your company in the Caspian region? The Caspian region is a focus area for MOL and the company is targeting for it to contribute to its ambitious E&P (exploration and production) strategy. The MOL Group has 15 years of operational experience in the region, which provides a really solid base for further business development. MOL, as a mid-size independent, is targeting those projects in which its technical capabilities in exploration (subsalt, complex targets) and field development (gas utilization, enhanced oil recovery) can deliver added value. MOL has a successful track record cooperating with bigger local and national

MOL GROUP

LOOKING AHEAD Alex Dodds, executive vice president of exploration and production at Hungarian MOL Group, says developments in the Caspian region will have a positive effect on his company’s mid-term and long-term production growth.


MOL GROUP Q&A


companies and this cooperation could lead to larger future

project partnerships.

What is the overall E&P strategy of your company?

The MOL Group has a very solid and diversified portfolio base.

We have a strong presence in central and eastern Europe

with excellent cash flow generation for further growth and

our diversified portfolio delivers opportunities in the world’s

key oil and gas regions, such as Russia, the Kurdistan Region

of Iraq, Pakistan, Kazakhstan, Africa, and the North Sea.

MOL plans to replace declining production in Hungary

and Croatia by finding growth opportunities elsewhere.

Strategically, my guidance as head of upstream has been

that our reserve-to-production replacement ratio must

exceed 100%, and our production growth annually must be

a minimum of 10% to 15%. In our business plan, we have

organic growth plans for all the countries that we operate in.

Our aim is to de-risk and economically recover 1.5 billion BOE

reserves and resources currently held in our organic portfolio,

and we have allocated USD 1 billion/yr to do that.

Secondly, we also have a number of inorganic options

that we are looking at in the North Sea, in Pakistan, possibly

in Russia, the Arabian Gulf, Angola, and elsewhere, and

we have a very strong balance sheet to be used for value-

creating merges and acquisitions. We also aim to achieve

a step change in upstream by adjusting our operational

model and efficiency levels to align with our ambitious

growth targets. We will continue the internationalization of

the company by attracting experienced international staff.

We have built our strategy on three pillars: people (hire the

best and motivate those who work for us), portfolio (offset

production decline/risks with growth and development

opportunities), and processes (improve our business

processes to become best in class).

What technologies are you using in the fields you operate in

the Caspian region?

Technology is a key enabler in our industry. In the subsalt low

porosity-permeability carbonate reservoirs in our Kazakh

blocks, MOL, together with its partners, is using leading-

edge 3D processing technologies to achieve high-quality

visualization, as well as sophisticated logging and core

analysis methods for reservoir characterization. Also, a key

target during our production and field development activities

is to minimize flaring and reach maximum gas utilization in

order to minimize emissions and protect the environment.

How would you describe the relationship between your

company and national oil companies (NOCs) in the region?

In the case of both MOL Group blocks in Kazakhstan,

KazMunaiGas Exploration Production, a subsidiary of the

Kazakh NOC, is the majority shareholder. MOL has been

working with them for more than 2 years and we have learned

a lot from each other. The two companies established a

working environment in which international best practices

are combined with local experience. This results in a

very successful and cost-effective operation. MOL fully

understands and supports every nation’s need to create a

good workplace and a bright future for its citizens. Therefore,

MOL will do its best to develop and support education

programs in order to create a foundation for the future.

Based on its positive experience, MOL is always open to

establishing E&P joint venture projects with local operators

and NOCs in the Caspian region.


company in this part of the world?

As in any other place in the world, a stable and predictable

legislative, political, and tax environment serves the basis

for the long-term success of a business. The Caspian region

still has room for improvement in this regard; generally,

the authority approval procedures are quite complicated

and slow, which can have a significant effect on successful

project implementation and execution.

Another significant challenge for all companies and

countries in the region is the safe and environmentally

effective disposal of sour gases that are produced with the

hydrocarbons. There are technologies and experience that

can be accessed in other parts of the world and it is therefore

important that this is done. JPT

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TECHNICAL PAPERS


Karachaganak field, a large

accumulation of gas and

condensate, began production in 1985.

Analysis and integration of the vast

amount of geological and production

data enabled building a reservoir model

having a high-quality history match

(HM). The workflow was reversed to

use the HM reference model as the

benchmark, modifying its characteristics

only in areas not controlled by well data,

and without perturbing the achieved HM

significantly. Petrophysical changes were

estimated by use of the distance from

productive wells and the magnitude

of the HM perturbations as control

parameters. The resulting end-members

models provided a reasonable spread in

the production forecast.

IntroductionThe Karachaganak field, in northwest-

ern Kazakhstan, was discovered in 1979.

The hydrocarbon column consists of ap-

proximately 1500 m of fluid in super-

critical conditions. As Fig. 1 shows, the

limestone/dolostone reservoir extends

from the uppermost Devonian to the

Lower Permian. Two main surfaces—

the C9 Tula maximum flooding surface

(Early Visean) and the C1 Carboniferous/

Permian unconformity—act as vertical-

transmissibility barriers.

The field was operated as a gas res-

ervoir, focusing on the top of the column,

(Objective 1) and drilled with vertical

wells, from 1985 till 1997. Then, Objective

2 focused on vertical wells drilled to the

lower gas-condensate section to produce

the condensate below the gas/condensate

contact. The next stage was development

of the liquid rim by means of deviated and

horizontal wells—Objective 3. To support

field pressure, a gas-injection program

was implemented in 2003–2004. A huge

amount of field data has been acquired.

Most of the wells were extensively cored,

and selective well tests were performed.

Dynamic behavior is linked strictly

to flow units and represents, at the most-

appropriate scale of observation, indirect

evidence of the geological framework af-

fecting the reservoir. Including these data

immediately into the geological model

appeared to be an optimized workflow.

Therefore, the reference deterministic

model was derived by a complex work-

flow focused on integration of static and

dynamic data with frequent iterations

between geologists and reservoir engi-

neers. Different releases of geological

and numerical models were optimized

step by step, through progressive tun-

ing. This workflow enabled obtaining a

final reservoir model with a high- quality

HM, but it required considerable effort in

terms of resources and time.

Uncertainty AnalysisEven if the reference model were con-

sidered a highly reliable tool to inves-

tigate the future development steps of

the field, the analysis and estimation of

uncertainties that affect the model were

mandatory. In making final decisions on

field development and related invest-

ments, management considered alter-

native scenarios (a high and, mainly, a

low scenario).

With the long production history of

the Karachaganak field, following a new-

field workflow to model the vast amount

of data would become very time consum-

ing. Following a workflow similar to that

used for the reference model, which in-

corporated all geological and production

data from the beginning, would make de-

veloping alternative scenarios with sig-

nificant differentiation very difficult.

The uncertainties of Karachaganak

field data were taken to be minimum

around productive wells, while uncer-

tainties increase toward areas not con-

trolled by well data. This concept is the

basis of the approach followed here: Un-

certainties affecting the reservoir were

investigated in a pragmatic manner, with

the HM of the reference model used as a

benchmark. It was assumed that reser-

voir uncertainty increases moving away

from well locations, where the reservoir

data are characterized with collected

petrophysical data (e.g., log and core)

and are endorsed by the historical pro-

duction behavior matched by the numer-

ical simulation.

From the well locations, a threshold

distance was estimated, beyond which

the petrophysical characteristics of the

reference model could be revised with-

out significantly perturbing or affecting

the quality of the reference-model HM,

as shown in Fig. 2. Thereby, two mod-

els were built by assuming petrophysical

worsening or improvement. The two al-

ternative reservoir-model scenarios rep-

resent possible end members consistent

with the available geological data while

endorsing a high-quality HM. The uncer-

tain volume pertains mostly to zones and

intervals not yet fully developed, such as

peripheral areas.

Parameter DefinitionEstimating the petrophysical change to

be applied to the unknown volume was

performed on the basis of cell statistics of

the scaled-up HM reference model. The

considered population represents aver-

age values at the scale of observation of

the scaled-up cells that are the final tar-

get of the analysis. Therefore, these data

are based on the well data and the whole

Handling Uncertainty Analysis in a Brownfield

This article, written by Dennis Denney, contains highlights of paper SPE 164810,

“Pragmatic Way To Handle Uncertainty Analysis in a Brownfield, Karachaganak

Field, Republic of Kazakhstan,” by F. Bigoni, E. Della Rossa, A. Francesconi,

K. Imagambetov, and G. Tumbarello, Eni E&P, prepared for the 2013 EAGE Annual

Conference & Exhibition incorporating SPE Europec, London, 10–13 June. The paper

has not been peer reviewed.


model, which includes estimated geolog-

ical trends describing the less-appraised

areas of the field.

The petrophysical change was de-

fined according to the following hierar-

chical steps:

1. Porosity multipliers (low and

high).

2. Water saturation, correlated to

porosity changes and adjusted

accordingly with the new porosity

scenarios (low and high).

3. Horizontal-permeability

multipliers were correlated to

porosity changes.

4. Vertical-permeability multipliers

were correlated to horizontal-

permeability changes.

Distance Based on Perturbation Re-

gion. After the petrophysical changes to

be applied to the scaled-up model are de-

fined (pragmatically with multipliers),

the volume/region in which they are to be

implemented must be determined. Con-

ceptually, at an initial stage, the 3D dis-

tance from production-well intervals was

taken into account. Multipliers were im-

posed beyond the determined threshold

distance. Several sensitivity runs were

made with different distance values to

check the HM perturbation. After making

sensitivity runs, it was possible, through-

out this workflow, to choose the appro-

priate minimum threshold distance be-

yond which the HM becomes perturbed.

This initial workflow was optimized

according to the following: Close to a pro-

ductive well, no change in petrophysical

properties would be applied; otherwise,

the HM would be lost. Unfortunately,

this concept could not be applied equally

to each productive well because the wells

differ from each other, particularly for

production potential and historical pro-

duction. Therefore, pressure depletion

was used as an alternative parameter to

define the region of perturbation.

Pressure-Depletion-Based Perturbation RegionPressure depletion was the best param-

eter to investigate. It is linked directly to

well-production behavior in terms of pro-

duction potential and production history.

The 3D distribution of pressure deple-

tion from the reference-model HM was

considered. Several sensitivity runs were

performed with different pressure cut-

offs to find the best pressure- depletion

values to define the perturbation region

by use of the same workflow and ratio-

nale followed for the 3D distance.

The Karachaganak field is charac-

terized by several pressure-regime areas

having pressure differences greater than

50 bar at the same depth. To reproduce

this regional pressure system dynamical-

ly, a skeleton of moderately sealing bar-

riers was defined during the reference-

model-building phase. Dynamic barriers

are associated with some of the recog-

nized seismic faults and with the complex

stratigraphic and sedimentological frame-

work. Their proper locations and sealing

degree were discussed with geologists and

supported by a quantitative analysis.

Field development is variable from

one area to another and at different strati-

graphic intervals. In such a situation, the

pressure-depletion cutoff values were not

unique for the whole field. Therefore, they

were set differently according to the zone

or stratigraphic interval. Sensitivity runs

were performed with different cutoffs to

determine the appropriate cutoff to use

for each depositional region. The choic-

es were evaluated by use of an object-

function detailed in the complete paper, in

which the discrepancy between the new-

Fig. 1—Karachaganak field: location map (left) and general reservoir subdivision (right). GOC=gas/condensate contact, OWC=condensate/water contact.

Fig. 2—Uncertainty concept.

P1

C1

C9

Astana

Atyrou

Almaty

Kazakhstan

UralMountains

GOC

OWC

C—Permian

B—Carboniferous

A—Pre-Tula

Threshold Distance

(Pe

tro

ph

ysic

al

Ch

an

ge

)

Known Area

Well Location

Increasing Distance

Unknown Area

Historical Data

Numerical Simulation Reference Model

Threshold Distance

(Pe

tro

ph

ysic

al

Ch

an

ge

)

Known Area

Well Location

Increasing Distance

Unknown Area

Historical Data

Numerical-Simulation Reference Model


scenario HM and the reference-model

HM was very small. In this case, it was

decided to consider an HM perturbation

(in terms of pressure and gas/conden-

sate ratio) ≤|4|%. Beyond these cutoffs,

multipliers were used that established a

transition zone in which the multipliers

were increased or decreased gradually.

Final Low and High Cases: Enhanced-Permeability AdjustmentsA critical issue in the Karachaganak field

is the presence of enhanced permea-

bility that is not recognized at the core

scale but affects, as estimated from well

data, approximately 15% of the reser-

voir. This enhanced permeability within

the generally poor rock-matrix perme-

ability increases reservoir performance

significantly. In the two models, the total

permeability (matrix+enhanced) was

considered and multiplier factors were

applied to matrix or to enhanced perme-

ability. These preliminary scenarios were

very similar to the reference model in

terms of enhanced-permeability distribu-

tion. To create the two end members, the

following adjustments were applied only

to the changeable volume of the reservoir:

◗ Low Case: no enhanced

permeability

◗ High Case: increase the enhanced

permeability

Risk Analysis on Cumulative-Oil-Production ForecastsThe perturbation region used for uncer-

tainty modeling within the HM frame-

work was integrated with a Monte Carlo

proxy-based risk-analysis workflow. The

parameters identified in previous phas-

es, essentially the multipliers of porosity

and permeability for the different dep-

ositional regions of the reservoir, were

used in an experimental-design and re-

sponse-surface modeling to describe the

probability of occurrence of different

scenarios in terms of liquid recovery. The

workflow was organized as follows:

1. Initial inputs were the

perturbation-region distance

and the parameter-uncertainty

multipliers, as estimated

from the low and high HM

deterministic models.

2. A screening of the petrophysical

uncertainties was carried out by

depositional region to define the

most effective combination of

region and parameter.

3. The selected most-significant

uncertainties were used to

run a simulation of a set or

combination of extreme

scenarios spanning the region/

parameter uncertainties with the

greatest effect, always preserving

the HM.

4. The liquid-recovery forecasts for

these extreme scenarios were

compared against uncertainty-

parameter multipliers and used

to build the response- surface

model (proxy model).

5. Then, the proxy model was

validated with independent

simulation runs for several

random intermediate scenarios.

6. Finally, considering uniform

distribution between the

minimum and maximum

uncertainty-parameter

multipliers and Monte Carlo

sampling, the proxy model

was used to generate random

scenarios.

The parameters with the greatest ef-

fect on the cumulative-liquid-production

forecast were those related to the less-

conditioned reservoir-depositional zones

(Permian, Western Area, and Flanks) , es-

pecially in terms of porosity and horizon-

tal permeability. The tornado chart of this

sensitivity is shown in Fig. 3.

ConclusionsKarachaganak is a brownfield with a long

production history. The final reference

model, built with integrated static and

dynamic data, achieved a high- quality

HM. Any alternative model should

achieve a similar-quality HM. The un-

certainty was investigated in a pragmatic

manner by use of a reference- model HM

as the benchmark and gradually chang-

ing the depositional region’s petrophysi-

cal properties, moving away from the

known data at production wells. The

pressure depletion and the magnitude

of the perturbations were used as con-

trol parameters, and the HM quality was

used as the selection criterion. Thereby,

two end-member forecasts were identi-

fied. These cases represented possible

alternative scenarios, and both were con-

sistent with the geological data and were

endorsed by a high-quality HM.

Finally, the two end-member fore-

casts were used as corner points for an

experimental-design procedure to de-

fine an optimal number of simulation

runs to build the proxy model for rel-

evant response variables. The validated

proxy models were used to generate ran-

dom profiles by a Monte Carlo approach,

and the corresponding P10, P50, and P90

cumulative-oil-production-forecast pro-

files were estimated. JPT

Fig. 3—Tornado chart for sensitivity on cumulative liquid production. The variations are given in terms of % with respect to the HM base case. WBU=Western Area.

Permian Porosity

WBU Porosity

Flanks Porosity

WBU Permeability

Permian Permeability

Flanks Permeability

–2 –1.5 –1 –0.5 0 0.5 1 1.5 2

TECHNICAL PAPERS


The formations of the Azeri-Chirag-

Gunashli (ACG) field offshore

Azerbaijan are weakly consolidated,

and openhole-gravel-pack (OHGP)

completions have become standard.

Development began in 1997, with more

than 70 high-rate (up to 45,000 B/D

per well) OHGP completions. Wellbore-

stability issues require OHGP screens to

be run in oil-based mud (OBM). Despite

excellent initial success, sand-control

failures began in 2008. A detailed

gravel-pack evaluation revealed that

early installations experienced screen

plugging in the lower section during

the installation process. This led to an

incomplete pack in the toe region and

subsequent screen failure as reservoir

depletion increased or when water

breakthrough occurred. The ultimate

risk was of lost production rather than

well control or loss of containment.

IntroductionThe ACG field is offshore Azerbaijan in

the southern Caspian Sea (Fig. 1). The

major producing formations are Pereriv

Units B, C, and D, which consist of lat-

erally continuous layers of sandstones,

with excellent intrafield connectivity and

permeability, that are interbedded with

shaly layers. The field’s north flank dips

at approximately 35° and has a 1000-m-

thick oil column between the gas/oil and

oil/water contacts. Voidage support is

achieved by water and gas injection, and

effective voidage replacement is consid-

ered critical to optimum reservoir drain-

age. All zones show high porosity and

permeability, with values in the ranges of

20–25% and 100–1,000 md, respective-

ly. The Pereriv Units B and D contain the

principal reserves and are the main pro-

duction contributors.

All targeted zones are weakly con-

solidated, with low unconfined com-

pressive strength (i.e., 60 to 665 psi),

and are highly nonuniform, as deter-

mined by laser particle-size analysis.

The formations can produce significant

quantities of sand (up to approximately

50–100 lbm sand/1,000 bbl oil) if pro-

duced unconstrained through cased/per-

forated completions. The bottomhole

temperature ranges from 145 to 175°F,

and the original formation pressure was

approximately 5,000 psi at 2900-m sub-

sea datum. The crude oil is 35°API grav-

ity, with a typical solution gas/oil ratio of

900 scf/STB.

Sand Control Standalone-screen (SAS) completions

were attempted in several Chirag wells

in the late 1990s, but the wells pro-

duced sand from the beginning and pro-

duction had to be choked back consid-

erably to control sand production. SAS

completions were superseded in Chirag

by OHGP completions in an attempt to

improve sand-control integrity by pro-

viding wellbore support. In contrast to

the performance of SAS completions,

OHGPs have provided excellent sand

control. Expandable-screen comple-

tions have not provided a similar level of

sand control.

Challenges at ACGWellbore Stability. The structure is

highly tectonically stressed, with the

maximum-stress tensor being hori-

zontal, the intermediate stress being

the overburden, and the least principal

stress being normal to the maximum

horizontal stress, despite the depth

of the productive interval. The shale

shows medium to high reactivity. The

combination of mechanical-wellbore-

stability problems and reactive shales

prevented the screens reaching total

depth (TD) during earlier OHGP instal-

lations that were run in a water-based

system of approximately 1.20 specific

gravity (SG). Wellbore stability is con-

trolled largely by running screens in

OBM, and increasing the mud weight to

1.35–1.38 SG.

Poorly Sorted Sand. The Pereriv forma-

tions are highly nonuniform with a high

fines content. Fines (<44 μm) content

ranged from 5 to 66%. Tectonic activity

Sand-Control Reliability of Openhole Gravel-Pack Completions


“Significant Increase in Sand-Control Reliability of Openhole-Gravel-Pack Completions

in the ACG Field—Azerbaijan,” by Yoliandri Susilo, SPE, Kevin Whaley, SPE,

Santiago Loboguerrero, SPE, Phillip Jackson, Natig Kerimov, Robert Anderson,

Patrick Keatinge, and Brian Edment, SPE, BP, prepared for the 2013 SPE European

Formation Damage Conference and Exhibition, Noordwijk, The Netherlands, 5–7

June. The paper has not been peer reviewed.

Fig. 1—ACG-field location.


coupled with a low degree of reservoir

cementation and grain-to-grain contact

has resulted in grain fracturing in which

individual sand grains fragment, making

the sands more difficult to control.

Highly Depleted Reservoirs. The con-

ditions for running screens in ACG

change continually, and the challenge

that emerged in 2009 and 2010 was dif-

ferential sticking. The differential-stick-

ing risk is caused partly by higher mud

weight, but more by the high levels of res-

ervoir depletion across the field.

High Drawdown. ACG OHGP wells

have been produced with a drawdown

as great as 1,800 psi. The total draw-

down (drawdown+depletion) values

have reached more than 3,500 psi in

the deepwater-Gunashli area, which has

pushed the limits for OHGP completions.

The depletion in the Chirag and deepwa-

ter-Gunashli areas is much higher than in

the Azeri area.

OHGP FailureDespite initial success of OHGP com-

pletions, sand-control failures began to

occur in 2008. Detailed gravel-pack anal-

ysis on data collected with multiple wash-

pipe gauges revealed that earlier installa-

tions experienced screen plugging on the

lower sections during installation. The

result was an incomplete pack in the toe

region and subsequent screen failure as

the reservoir pressure depleted or when

water breakthrough occurred. Approx-

imately 65% of the ACG OHGP sand-

control failures were caused by exces-

sive mud plugging of the wire-wrapped

screen (WWS) at the toe of the well.

Design Changes With the better understanding of the root

cause of sand-control failure from the

earlier OHGP wells, six key changes were

implemented to mitigate the problem.

TD Criteria. The importance of having

a sump in the underlying shale (nonpro-

ductive zone) was not realized in the ear-

lier OHGP wells, which had little sump

below the sand. The plugged screen at the

toe (i.e., screen without gravel behind it)

was across the productive interval caus-

ing sand-control failure at this section

later. Fig. 2 shows the TD of an openhole

section extended into the shale (nonpro-

ductive interval) as far as 40 m, if possi-

ble without penetrating to the next sand

interval. The sump in the shale below

the productive-sand interval provides a

place to set the bottom joint(s) of the

OHGP screens. The bottom joint(s) of the

screen tend to become plugged when run

in OBM, therefore the toe of the screens

may not have gravel packed around them.

Consequently, leaving the bottom joint(s)

of screen in a shale improves the long-

term sand-control integrity of the well.

Screen-Bottomhole-Assembly Design.

In early 2010, the weep-hole design was

replaced with a shearable equalizing valve

and rupture disk, as shown in Fig. 3. This

system prevents fluid from self-filling the

drillpipe while running into the hole and,

hence, reduces screen plugging.

Mud Conditioning. Before 2008, no

visual-check criteria had been estab-

lished for tests performed on a WWS cou-

pon. However, it was realized in early

2008 that although the mud passed the

time criterion, it still contained a large

amount of solids, which were plugging

the screens during installation of the

lower completion.

Wellbore Cleanout. In an effort to im-

prove wellbore-cleanout efficiency, the

bottomhole-assembly configuration was

modified to allow the flow rates for per-

forming the entire mud-conditioning se-

quence to be increased to the maximum

feasible limits, which are almost always

greater than the drilling mud-flow rate.

Ultrafine-Grained Barite. Screen plug-

ging continued to be observed in the new

OHGP wells; although improved, clean-

out was still poor in some wells. After

May 2010, it was realized that in some

wells the cleanliness of OBM at the sur-

face at the end of the mud- conditioning

phase was not representative of the

cleanliness of OBM left in the open hole.

The magnitude of the difference varied,

but it seemed as though the mud in the

open hole had very limited condition-

ing. One possible explanation was that

the reservoir-drilling fluid (RDF) ex-

perienced severe barite sagging in the

open hole and that the conditioned RDF

being circulated was simply overrunning

much of the dirty RDF in the open hole.

Ultrafine-grained barite RDFs were in-

troduced to help alleviate the barite-sag

issue and reduce the amount of large sol-

ids in the fluid system.

Rapid Post-Job Analysis. Before early

2008, two wash-pipe gauges were run

during OHGP deployment (one at the

casing shoe and one at the bottom of

screens). This placement, combined with

other factors, made it difficult to identi-

fy the screen-plugging issue. To mitigate

screen failure of the nongravel-packed

section at the toe, a rapid post-job analy-

sis is performed after the gravel-pack

procedure is completed and the wash-

pipe gauges are recovered to surface. If

the gauge-data analysis shows that the

plugged-screen length (with no gravel be-

hind the screen) is across the productive

interval such that it could create concern

Fig. 2—TD with longer shale section to place plugged screen across nonproductive interval.

Fig. 3—Wash-pipe weep holes (left and middle) and rupture disk (right) to replace the weep hole (current practice).

No flow wherethere is pluggingtherefore no sandis produced

Old Washed-Out Weep Holes:Approx. 2×dia.= 4×flow rate=

4×the pluggingsNew 0.125-in. Weep Hole

Replace WithRupture Disk

for sand-control integrity during pro-

duction, a bridge plug is installed above

the plugged screen immediately upon in-

stalling the upper completion (tubing).

This preventive action is considerably

more time and cost efficient compared

with fixing the failure after the well starts

to produce sand, which requires an ad-

ditional complex well intervention. To

provide improved data quality for the

post-job analysis, five to seven wash-

pipe gauges to record external pressure

and a downhole gauge above the gravel-

packing service tool (recording external

and internal pressures) are run on each

OHGP job.

Results Following design improvements made

after 2008, the amount of screen plug-

ging observed in OHGP completions

decreased and sand-control reliability

improved significantly, as indicated by

the reduction in sand-production-relat-

ed losses shown in Fig. 4. Since mid-

2008, most of the OHGPs have expe-

rienced less than two to 2½ joints of

plugged screens at the start of produc-

tion operations. Because the bottom 1½

joints are placed in shale at TD, effec-

tively all of the openhole section is now

packed fully on all wells. Since 2008, the

OHGPs that have more than two joints

of screens plugged at the start of pro-

duction have had plugs placed to iso-

late the toe of the well, or gauge analysis

showed that the toe was packed by use

of the shunt tubes (the pressure surg-

es during shunting have been observed

to cause partial unplugging of screens

sometimes), or the base of the Pere-

riv Unit D was silt, which does not re-

quire isolation.

Sand-Control Reliability. The de-

sign limits for sand production of indi-

vidual wells and platforms are 10 and

5 lbm sand/1,000 bbl oil, respectively.

The ACG OHGP sand-production lev-

els are monitored carefully on a regular

basis. There are multiple older wells that

produce above the single-well 10-lbm-

sand/1,000-bbl-oil threshold. Wells

completed after 2008 show improve-

ments to mitigate the mud-plugging issue

at the toe of the screens. Data show that

all new wells produce below the 10-lbm-

sand/1,000-bbl-oil single-well threshold

and that most wells produce below the

5-lbm-sand/1,000-bbl-oil average-well

threshold. Most of time, the wells produce

below 1 lbm sand/1,000 bbl oil, which in-

dicates a good OHGP completion.

Production Loss. These improvements

resulted in greatly reduced screen plug-

ging, with increased pack efficien-

cy across the productive interval. A step

change in OHGP reliability resulted,

with no sand-control failure over the last

24 completions. The detailed understand-

ing of the failure mechanism also facilitat-

ed a successful intervention campaign to

remediate several failed OHGP wells. Five

of the failed OHGP wells that were com-

pleted before the end of 2008 have been

brought back on line by installing a bridge

plug inside the screen connection above

the plugged-screen interval. As Fig. 4

shows, the efforts have reduced pro-

duced-sand related losses by approxi-

mately 60,000 B/D. JPT

Fig. 4—Sand-production-related production losses in ACG OHGP wells.

1-Jan-10

10090

80

70

60

50

40

30

20

10

0San

d re

late

d lo

sses

, 1,0

00 B

OE

D

2-Mar-10

1-May-10

30-Jun-10

29-Aug-10

28-Oct-10

27-Dec-10

25-Jun-11

26-Apr-11

25-Feb-11

24-Aug-11

23-Oct-11

22-Dec-11

20-Feb-12

20-Apr-12

19-Jun-12

18-Aug-12

17-Oct-12

16-Dec-12

Fuel for Thought

Energize your career with

training courses from the

Society of Petroleum Engineers.

Get up-to-date industry knowledge

from the people who wrote the

book on E&P. Courses are offered at

multiple locations around the world.

Learn more at www.spe.org/training

where you can browse the schedule

and register for courses that meet

your interests.

TECHNICAL PAPERS


Casing-, liner-, and completion-

running operations are critical in

the well-construction process. Failure

to reach the required setting depth can

affect well economics significantly with

additional costs, deferred production,

and lost reserves. A substantial portion

of nonproductive time (NPT) associated

with these operations is the result of

stuck pipe. A new advisory system was

developed to enhance monitoring the

running of tubulars into a wellbore.

This Web-based system integrates

real-time data, analytical capability,

and informative displays to identify

early-warning indicators associated

with stuck pipe, mud losses, and

other anomalies.

IntroductionCasing-running operations have be-

come complex with longer extended-

reach and deeper high-pressure/high-

temperature wells. Extended-reach

wells require managing casing-running

frictional drag, and deep wells require

managing high tensile loads and surge

pressures in close- tolerance casing de-

signs. Very-high casing-running weights

can be a challenge for rig equipment,

including derrick-load capacity, slip-

crushing concerns, and required dedi-

cated high-strength landing strings. For

wells that require underreamed hole

sections, there is the added challenge of

achieving adequate zonal isolation, pos-

sibly with the use of bow-spring central-

izers, which increase frictional drag in

cased-hole sections.

A casing-running advisory system

was developed as part of a larger well-

adviser program and builds capabili-

ty by integrating real-time data with

predictive tools, processes, know-how,

and expertise to enable timely, well-

informed, and effective operational de-

cisions. The system should reduce the

number of major NPT events. The sys-

tem is not intended to replace existing

expertise but to expand expertise by en-

hancing organizational capabilities. The

well-adviser program integrates various

console displays, leading to the term

casing-running console. In this paper,

the term casing running also applies to

running liners, tiebacks, and comple-

tion tubulars.

Casing running is a highly repeti-

tive process and, normally, follows a

predictable sequence of events—pick-

ing up a new casing joint from the V-

door or derrick, connecting the joint to

a string already held in the slips, picking

up thecombined string to clear the slip

area, removing the slips, running the

string in the hole, setting the casing

back into the slips, and repeating. Vari-

ations to this sequence include chang-

ing elevators, hoisting casing to obtain

pic up measurements, installing central-

izers, filling casing, and the driller react-

ing to unexpected downhole problems.

DesignA common approach for monitoring

casing runs is to manually record a sin-

gle snapshot of the hookload value read

from a gauge on the rig floor as each

casing joint is run in the hole. This re-

corded value is compared with mod-

eled hookload drag curves by plotting

it on a graph. Any persistent deviation

from the expected trend may indicate

the onset of a potential problem. This

approach sometimes requires a dedi-

cated rigsite resource to take readings,

provide interpretation, and make rec-

ommendations. Although this approach

may work well in many cases, often it is

unable to deal with more-complex situa-

tions in which hookloads exhibit signifi-

cant variation and sometimes hidden or

invisible trends.

In 2010, a feasibility study was un-

dertaken to examine whether in-house

techniques could be codified and in-

tegrated with a real-time data system

to provide early warning indicators of

potential casing-running problems.

Some of the technical challenges would

be to extract information from existing

real-time data feeds and conduct anal-

ysis and interpretation for display in a

timely manner.

First Production VersionHow the user interface should look was

based on input from operational teams

and the domain expert. It was deter-

mined that including more detail in the

graphical designs during the specifica-

tion phase enabled faster development

of the end product. To minimize devel-

opment time, existing widgets and dis-

plays within the visualization tool were

used. On the basis of user specifications

and value assessments, the original con-

cept was simplified to include four dis-

play widgets. The screenshot in Fig. 1

shows all four casing-running compo-

nents displayed together.

Hookload-Signature Widget. There is

a real-time display indicating the hook-

load and block positions while a single

joint of casing is run in the hole. Hook-

load data are analyzed to calculate and

display parameters of interest and high-

light early warning indicators. Thumb-

nail images of up to four previous casing

joints can be shown in the history panel.

All previously run casing joints can be

viewed separately.

Real-Time Casing-Running Advisory System Reduces Nonproductive Time

This article, written by Dennis Denney, contains highlights of paper SPE 166616, “New

Real-Time Casing-Running Advisory System Reduces NPT,” by Colin J. Mason, SPE, BP

Exploration; Jan Kåre Igland, SPE, Kongsberg Oil and Gas Technologies; Edward J.

Streeter, SPE, BP Exploration; and Per-Arild Andresen, SPE, Kongsberg Oil and Gas

Technologies , prepared for the 2013 SPE Offshore Europe Oil and Gas Conference and

Exhibition, Aberdeen, 3–6 September. The paper has not been peer reviewed.


Drag Chart. This widget is an aggre-

gated display of time-based hookload

data in a depth-based format. Real-time

hookload values are plotted against

modeled drag curves to help identify de-

viations and forecast potential issues.

Immediately below this chart is a li-

thology display, which enables corre-

lating changes in hookload trends with

formation changes. Wellbore mark-

ers are used to define geometry chang-

es, such as the start and end of the

openhole section.

Trip Schedule. This widget shows the

average block speed per joint while run-

ning in the hole (blue symbols) and

when picking up (red symbols) each

casing joint. These values are compared

with the planned trip-in- and trip-out-

schedule limit curves calculated with

surge- and swab-modeling software.

The unshaded areas represent desired

running speeds.

Zone Widget. This is a traffic-light-type

display of key casing-running parame-

ters to maintain operational values with-

in target operational limits. This dis-

play is updated on a joint-by-joint basis.

High and low hookload, tripping-in and

tripping-out speeds, static friction, and

hookload variation are parameters con-

figured in the zone display. User-defined

threshold values are used to set green-,

amber-, and red-zone ranges.

Input and Output DataThe system operates by capturing and

analyzing real-time date/time, bit-

depth, block-position, and hookload

data. The time-indexed data stream re-

quires an input frequency of 1 Hz to

provide the required granularity to de-

fine the behavior of the casing-running

process adequately. The visualization

tool updates the real-time hookload-

signature display every 5 seconds. The

drag-chart, trip-schedule, and zone dis-

plays are updated only after each joint

has been run to depth.

The system generates a group of

output-data files that contain a his-

tory of the entire casing run. One of

the files contains a statistical break-

down of the operation on a joint-by-

joint basis. These data can be used to

identify performance metrics (e.g., time

to make connections) or to better un-

derstand risks (e.g., evolution of static

friction trends).

Field TrialA field trial was planned for December

2010 to test a prototype system. The de-

velopment team worked with the Azer-

baijan regional office to identify a candi-

date well and casing run that would be of

reasonable duration to test the system

fully. The field trial was primarily to test

the system with no direct communica-

tion with the rigsite. However, if the

console indicated a problem associated

with the casing-running process, an es-

calation plan was put in place to com-

municate to a nominated engineer who

would be responsible for relaying com-

ments to the rigsite team. The 9⅝-in.-

casing run took place between 6 and 9

December 2010. The previous 13⅜-in.-

casing shoe was set at 4196-m mea-

sured depth (MD), leaving a 1293-m,

12¼×13½-in. underreamed openhole

section. The casing was centralized

along the length that occupies the open

hole and a portion of the overlap with

the preceding casing string.

Running the Liner. As shown in Fig. 2,

a close-tolerance 1400-m-long 13⅜-in.

liner was to be run into a 70°- inclination

hole. The liner had to pass through 721 m

of 20-in. surface casing, 2169 m of close-

tolerance 16-in. liner, and 1300 m of

17-in. underreamed section to 4246-m

MD. The 13⅜-in. liner was run in the

hole by use of drillpipe and heavy-wall

drillpipe. Stiffness concerns about run-

ning centralized 13⅜-in. liner through

the close-tolerance confines of the 16-in.

Fig. 1—Composite display of the casing-running advisory system.

Fig. 2—Well-design for the 13⅜-in.-liner run.

0

True

Ver

tical

Dep

th F

rom

Bas

e of

Rot

atar

y Ta

ble

(m)

500 16-in.-Liner topat 721-m MD

20-in.Shoeat 822-m MD

16-in. Shoe at 2890-m MD

13 3/8-in. Shoeat 4246-m MD

13 3/8-in.-Linerat 2790-m MD

Centralizers 17-in. Hole toat 4246-m MD

70-in.

70-in.

1000

2000

3000

1500

2500

-1000 -500 500 1000

Horizontal Deviation (m)

1500 2000 2500 3000 400035000


liner in a build section required central-

izing the string with one device per joint

over the bottom 200 m and top 200 m

of the liner. The middle section of the

liner was centralized every other joint to

help improve standoff and resist differ-

ential sticking. Bow-spring centralizers

were selected, and autofill float equip-

ment was used to manage surge pres-

sures when running the 13⅜-in. liner

through the 16-in. liner.

Fig. 3 shows the final real-time drag

chart from the successful 13⅜-in.-liner

run. The graph shows real-time hook-

load data (noisy blue symbols), static-

friction events (red symbols), and the

five common curves derived by drag

modeling. The real-time hookload data

tracked the tripping-in drag curve accu-

rately for the entire run. Regular pickup

events can be observed taking place ap-

proximately every five stands, even in

the openhole section. In this case, a dif-

ference between the modeled and actual

pickup values can be detected. Once the

liner was 400 m into the openhole sec-

tion, growing static-friction events were

detected after each connection. These

events are shown as red symbols indi-

cating that the rigsite adopted appropri-

ate practices to avoid becoming stuck. In

this case, there was only enough weight

available to break the static- friction

force as the liner approached its target

depth. In terms of learning, the instal-

lation frequency of only one centralizer

per two joints over the middle section of

the casing may have led to the onset of

differential sticking.

Conclusions◗ The casing-running

advisory system identified

early warning signs of

potential problems that may

not have been identified by use

of conventional monitoring

methods. In those cases,

interventions were made

that prevented major

NPT events.

◗ The presentation of casing-

running information in a

reliable and timely manner

and in a consistent format

enabled more-rapid and

-accurate interpretations

of events. One of the major

benefits of the system is to

bring real-time visualization

to a wider support group that

can participate meaningfully

in monitoring and in

operational decision making.

◗ The system can be used

for forensic purposes after

unexpected events on

wells not directly linked

to the system. By feeding

historical data to the console,

more-rapid analysis and

better interpretation resulted.

◗ Use of the system

has encouraged more

consideration about

torque/drag and swab and

surge modeling. There is

more awareness of issues

such as accounting for

stiffness effects, close-

tolerance well designs,

centralizer selection and

placement, and engaging

more closely with

service providers before

casing runs.

◗ The potential tendency to

chase the curve and attempt

to make the drag model

match the real-time hookload

data is discouraged. The

real value is in trying to

understand actual events

downhole, not to force

the curves to fit the

data artificially. JPT

Fig. 3—Drag chart for the 13⅜-in. liner run. FF=friction factor.

16-in.-Liner topat 721-m MD

800

700

600

500

400

300

200

100

00 500 1000 1500 2000

MD (m)

Hoo

kloa

d (1

,000

lbm

)

2500 3000 3500 45004000

16-in. Shoe at2890-m MD

17-in.-Hole to4246-m MD

Hookload

Static friction Events

90% Yield Stress Limit

Pick-Up Weight FF=0.30/0.30

Free Rotating Weight

Slack-Off Weight: FF=0.30/0.30

Helical Buckling Limit

TECHNICAL PAPERS


To drain reservoirs in a Caspian

Sea field effectively from a single

offshore ice-resistant stationary

platform, the operator wanted to

geosteer extended-reach 8½-in.-

lateral wellbores at the maximum

rate of penetration (ROP) and

reach total depth (TD) in one run.

Development of the Korchagina field

would require extended-reach-drilling

(ERD) horizontal wells with stepouts

of up to 8000 m. The shallow true

vertical depth (TVD) of the reservoir

combined with low formation strength

and reactive shale requires high mud

weight for stability, creating a narrow

equivalent-circulating-density (ECD)

window. A new bottomhole assembly

(BHA) was developed to improve

drilling these ERD wells.

IntroductionThe Korchagina project is an offshore

development in the Russian Caspian

Sea (Fig. 1) and is a complex technical

project. Hydrocarbons in this field are

trapped in an anticlinal feature with

70 m of natural-gas cap rimmed by 20 m

of viscous oil. To avoid early gas pro-

duction that would lead to catastrophic

water breakthrough, it is critical to keep

the horizontal borehole within a nar-

row vertical corridor of 4- to 5-m thick-

ness to ensure maximum oil recovery.

To accomplish the objectives would re-

quire the latest methods/technologies

and would require adhering to stringent

environmental regulations. Drilling of

the Korchagina field commenced at the

end of 2009.

At the time this paper was written,

14 wells had been drilled from the ice-

resistant stationary platform MLSP-1 on

the Korchagina field, including six ERD

wells, with an ERD ratio (TD/TVD) of

up to 4.25 and a maximum total depth

of 7600 m. The last section of a typical

well for this project consists of drilling

a horizontal wellbore of up to 4700 m

through the reservoir. To remain in the

oil-pay zone, well-placement engineers

work with geologists to understand the

efficiency of azimuthal changes with re-

gard to formation strike. Also, the bore-

hole must be steered a certain distance

away from fluid contacts; thus, the TVD

must remain constant.

This paper highlights challenges of

the horizontal sections in the Korchag-

ina field and the solution in terms of

BHA design, polycrystalline-diamond-

compact (PDC) -bit design, and drill-

ing fluid. An integrated technical ap-

proach allowed Lukoil to run its first

challenging offshore ERD project in

Russia successfully.

Planning of Well P-116 Wellbore Trajectory. The objective of

Well P-116 was to drill a 3770-m hori-

zontal section in one bit run, at maxi-

mum ROP, while remaining in a 1.5-m-

thick drilling corridor. The well plan

called for a maximum of 2°/30-m turn

rates while drilling horizontally. This

was the longest horizontal section for

the project at that time.

Geology and Well PlacementAs Fig. 2 shows, horizontal sections in

Korchagina are a succession of sand-

stones and siltstones with hard-lime-

stone stringers. When the bit pene-

trates the hard intervals, a sharp drop

in ROP occurs along with a loss of steer-

ing control. The formation deflects the

BHA downward, sometimes making

it difficult to recover trajectory con-

trol. Key challenges for well placement

are the thin oil zone (approximately

20 m between the gas/oil and oil/water

contacts), faults, and geomechanical

restrictions in azimuth in drilling. Be-

cause of the reservoir characteristics,

the well-placement team, along with the

geological team, provided real-time in-

structions to the directional drillers re-

garding making turns to remain within

the reservoir at all times to extend the

wellbore into the pay zone.

BHA. The BHA includes a newly de-

signed seven-blade PDC bit, a rotary-

steerable system (RSS) with a flex joint,

and measurement-while-drilling and

logging-while-drilling tools. The BHA is

a push-the-bit RSS. Full rotation of the

drilling string reduces drag, improves

ROP, decreases the risk of sticking, and

Bottomhole Assembly Improves Extended-Reach-Drilling Rate of Penetration by 62%


“Integrated BHA Improves ROP by 62% in ERD Operation Saving 29 Days Rig Time;

Sets Russian Lateral-Length Record,” by Timur Kasumov, SPE, Alexey Valisevich,

and Vasily Zvyagin, Lukoil, and Mirat Kozhakhmetov, Romain Griffon, SPE,

Alexander Mironov, and Wiley Long, SPE, Schlumberger, prepared for the 2013 SPE

Arctic and Extreme Environments Conference & Exhibition, Moscow, 15–17 October.

The paper has not been peer reviewed.

Fig. 1—Korchagina project—offshore Caspian Sea, Russia.


achieves excellent hole cleaning. Use of

the flex joint enables increased dogleg

capability. To reduce the ECD, a tapered

string of 4½-in. and 5-in. drillpipe was

used above the BHA.

Bit-Selection In the five horizontal wells drilled be-

fore Well P-116 in Korchagina, an 8½-in.

MDi713 PDC bit was used with the RSS.

The bit was a seven-blade fixed-cut-

ter bit with 13-mm PDC cutters. While

this bit provided consistent and reliable

drilling performance, the drilling team

needed to improve the ROP while deliv-

ering the low-vibration response pro-

vided by the existing BHA. Obtaining

a higher ROP would be critical because

the 8½-in. interval of Well P-116 was ex-

pected to be the longest lateral drilled to

date. Improving upon the 24-m/h ROP

average value of the bit used in the pre-

vious five wells would provide an op-

portunity to reduce the drilling time for

the section.

Land experience in an eastern Sibe-

ria oil field with a different 8½-in. PDC

bit, fitted with special PDC cutters, in-

dicated that above-average ROP could

be achieved when the bit was used with

an enhanced downhole motor. Although

the geology of the two fields is dramat-

ically different, the drilling team re-

quested the bit company to investigate

the possible use of the alternative PDC-

bit type in the Korchagina horizontal-

drilling application.

After analyzing all of the available

data, the MDSi716 bit was deemed ac-

ceptable for use in the Korchagina field.

Reviewing the geology and the dull-bit

conditions from offset runs showed that

increasing the PDC-cutter size from 13

to 16 mm would be an acceptable change

for improving ROP. To account for the

increased cutter-wear risk with the lon-

ger interval to be drilled in Well P-116,

the MDSi716 PDC bit included special

PDC cutters and additional backup PDC

cutters on three of the seven blades, as

shown in Fig. 3. While backup blades

can lead to an increased risk of bit ball-

ing caused by inefficient PDC-cutter

cleaning on the backup cutting struc-

ture, the evaluation of the geology and

the offset dulls deemed the risk of bit

balling to be negligible. Simulating the

downhole drilling conditions provided

the engineering teams with an under-

standing of the benefits that could be

provided by switching from the MDi713

type of PDC bit to the MDSi716.

Drilling FluidIn extended-reach and horizontal wells,

water-based drilling fluids provide only

limited lubricity. To drill 2500–3000-m-

long horizontal sections, frictional

forces become an issue and create ad-

ditional risks while drilling and run-

ning casing (depending on formations,

drilled-solids content, overbalance, and

other issues), especially when running

completion strings. An oil-based-mud

(OBM) system was considered fit for

drilling Well P-116. The OBM system

is fully inert to all rock types, which

eliminates many problems related to

formation instability resulting from

poor inhibition.

Fluid Selection. In addition to gener-

al features of the selected mud type,

the system had lower-end rheology that

is comparable with traditional OBM

systems. However, this mud system

maintained good cuttings-carrying ca-

pacity because of its high rheology at

low-shear rates. Low rheology keeps the

ECD range within the mud-weight win-

dow without exceeding the loss gradient

or falling below the formation-collapse

gradient. The Neocom formation in the

Korchagina field contains high-perme-

ability zones, as great as 2 darcies. To

prevent differential sticking, a proper

bridging agent was selected to create a

thick low-permeability filter cake in line

with the ideal-packing theory.

Coefficient of Friction. Oil-based drill-

ing fluids have higher lubricity com-

pared with water-based muds. How-

1500

TV

D (

m)

TV

D S

ubse

a (m

)

Horizontal Offset (m)TVD Scale: 7.41

1520

1480

1500

1520

1540

1540

1560

1580

900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700

Fig. 2—Cross-section view showing formation dip in the Korchagina field.

Fig. 3—8½-in. MDi713 bit (left) and 8½-in. MDSi716 bit (right).


ever, field data showed that an even

lower friction factor was required for

the more-challenging tasks of this proj-

ect. Later, OBM at field conditions was

treated with an increased amount of lu-

bricant. An analysis was used to evaluate

the possibility of drilling longer extend-

ed-reach wells. The lubricant concen-

tration was raised to approximately 5%

at 5000-m measured depth. While add-

ing the lubricant, further well deepen-

ing was stopped to obtain more-reliable

results. These results indicate that the

lubricant can be used for drilling longer

horizontal sections in the north Caspian

region (longer than 7500 m).

Reduce Cuttings. On the basis of a geo-

mechanical study, the drilling-fluid den-

sity combined with inhibiting properties

maintained wellbore stability during the

drilling process. Consequently, the low

washout coefficients combined with the

low mud-on-cuttings values resulted in

a significant reduction of cuttings-dis-

posal volumes.

ResultsThe first ERD well of the project was

Well P-107, with an ERD ratio >2. Then,

three more ERD wells were drilled with

8½-in. bits, of which Well P-116 was the

last. The total reach of Well P-116 was

4730 m at 1564-m TVD, resulting in an

ERD ratio of 3.02. Well P-116 was the

longest well drilled with 8½-in. hole

size. For wells drilled after Well P-116,

the ECD limitation and need for an in-

creased mud-weight window while drill-

ing longer horizontal sections led the

engineering team to propose drilling an

oversized hole by switching from 8½-

to 9½-in. hole while drilling the longer

horizontal sections. All of the long wells

following Well P-116 were drilled with

9½-in. hole size.

The ROP for the horizontal section

of Well P-116 was 55 m/h. The offset ROP

average was 21.3 m/h. This performance

on the Well P-116 horizontal section rep-

resents an increase of 159% compared

with the previous 11 wells. The ROP in-

creased by 62% compared with the best

offset well, which was drilled at 34 m/h.

The distance-drilled/circulating-hour

value is a good indicator of drilling per-

formance. The record on the project at

the time of writing was 20 m/circulat-

ing hour. This performance indicates

optimal hole cleaning, excellent bore-

hole condition, no equipment failure,

and minimized connection time (allow-

ing adequate circulation between con-

nections). There was 185 hours of cir-

culation through the downhole tools in

one run.

The new bit design improved ROP

significantly vs. the previous design and

established a high level of excellence for

the wells that followed. Because drill-

ing the horizontal section represents

approximately 30% of the total project

duration, flawless execution improved

the overall drilling performance signifi-

cantly. As Fig. 4 shows, Well P-116 was

drilled and completed 26% faster than

the previous best well, at an average

of 10.6 d/1000 m. The dogleg severity

achieved while geosteering was as great

as 3°/30 m, with the reservoir being

tracked at all times and increasing the

penetration length of pay zone. In ad-

dition, tortuosity was reduced, which

lowered the overall drag when running

the openhole completion. The section

was completed with zero nonproduc-

tive time. JPT

Fig. 4—Korchagina-field drilling from spud to end of completion.

50

Ave

rage

Dril

ling

Tim

e (d

/100

0 m

)

45

40

35

30

25

20

15

10

5

0P-11 G-01 P-14 P-12 P-110 P-113 P-107 P-104 P-116 P-114 P-109 P-105 P-117G-01

Well

34.6

31.3

22.1

43.3

23.224.9

19.6

10.6 10.212.3

10.8 10.7

14.3

17.9

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