32

easure and record well performance

ors placed downhole during completion.

eers information essential to dynami-

s, allowing them to optimize production

efine field development and adjust

Permanent Monitoring—Looking at Lifetime Reservoir Dynamics

Alan BakerJohn GaskellAberdeen, Scotland

omasneruso, France

Trond UnnelandStatoilBergen, Norway

For help in preparation of this article, thaZaimul Arifin and Barry Nicholson, WireJakarta, Indonesia; Mary Ellen Banks, SchDoll Research, Ridgefield, Connecticut, UBundy, Conoco Indonesia, Jakarta, IndonChérière, Alp Tengirsek and Imran Kizilb& Testing, Montrouge, France; Gilbert CoGlotin and Peter Soroka, Schlumberger-RCentre, Clamart, France; Eric Decoster, WTesting, Rio de Janeiro, Brazil; Marcelo P& Testing, Anaco, Venezuela; and John PExploration, Aberdeen, Scotland.

In this article, UNIGAGE (downhole recoof Schlumberger and Windows is a markCorporation.

Permanent monitoring systems m

and reservoir behavior from sens

These measurements give engin

cally manage hydrocarbon asset

techniques, diagnose problems, r

reservoir models.

John JefferyElf Enterprise Caledonia Ltd.Aberdeen, Scotland

Alan ThTony VeClamart

nks to Elwinline & Testing,lumberger-SA; Thomas

esia; Lilianneash, Wirelinenort, Bernardiboud Productireline &

rillo, Wirelineucknell, BP

Oilfield Review

rder) is a mark of Microsoft

33Winter 1995

nPermanent moni-toring system. Datarecorded by per-manent gaugesmay be transmit-ted via satellite to oil companyoffices for use inreservoir modeling.

1. Lilley IJ, Douglas AA, Muir KR and Robinson E: “Reser-voir Monitoring and Wireline Logging in Subsea Wells,”paper SPE 18357, presented at the SPE EuropeanPetroleum Conference, London, England, October 16-19, 1988.Shepherd CE, Neve P and Wilson DC: “Use and Appli-cation of Permanent Downhole Pressure Gauges in theBalmoral Field and Satellite Structures,” SPE ProductionEngineering 6, no. 3 (August 1991): 271-276.Carter PJ and Morel EH: “Reservoir Monitoring in theDevelopment of Marginal Fields: Ivanhoe, Rob Roy andHamish,” paper SPE 20978, presented at Europec 90,The Hague, The Netherlands, October 22-24, 1990.

Reservoir development and managementtraditionally rely on early data gathered dur-ing short periods of logging and testingbefore wells are placed on production.Additional data may be acquired severalmonths later, either as a planned exercise orwhen unforeseen problems arise. Such dataacquisition requires well intervention andnearly always means loss of production,increased risk, inconvenience and logisticalproblems, and may also involve the addi-tional expense and time of bringing a rigonto location.

Permanent monitoring systems allow adifferent approach (above ). Sensors areplaced downhole with the completion stringclose to the heart of the reservoir. Moderncommunications provide direct access to

sensor measurements from anywhere in theworld. Reservoir and well behavior maynow be monitored easily in real time, 24hours a day, day after day, throughout thelifetime of the reservoir. Engineers canwatch performance daily, examineresponses to changes in production or sec-ondary recovery processes and also have arecord of events to help diagnose problemsand monitor remedial actions, rather likemonitors in a power plant’s control room.

Most systems in operation record bottom-hole pressure and temperature, but othermeasurements, such as downhole flow rate,are being introduced and may becomecommon in the future. However, pressureand temperature provide dozens of benefi-cial applications.1 This article reviews thedevelopment of permanent monitoring,looks at applications with several examplesand describes the hardware.

1960 Technology

Current Technology

Insulatedoutlet forwire

Pressuregauge

Combinationwire clamp &wire protectoron eachtubing collar

Wire Cableprotector

Gaugemandrel

Pressure/temperaturegauge

Cable

The Technical Challenge: How Permanent is Permanent?Although permanent monitoring systemshave been around for a number of years, thetechnology has evolved fairly slowly. Relia-bility was a major issue with early installa-tions (next page, middle).4 The first perma-nent pressure gauge run by Schlumbergerwas for Elf in Gabon (Africa) in 1972 fol-lowed one year later by the first North Seainstallation on Shell’s Auk platform. Theseearly systems were essentially adaptations ofelectric wireline technology. A standardstrain pressure gauge was clamped to thetubing and ported to monitor tubing pres-sure. A stranded single-conductor loggingcable was strapped to the outside of the tub-ing exiting at the wellhead. Data wererecorded on a standard acquisition unit.

Many early failures were caused by dam-age during installation or by cable problemsat a later date—either by loss of electricalcontinuity or breakdown of insulation caus-ing a short circuit (next page, top). Statoilreport that many cable failures occurred atsplices and now request splice-free cables.Detailed analysis, such as that performed byPetrobras on systems run in Brazil and theNorth Sea, shows how reliability hasimproved.5 More recently a detailed researchand development project by Schlumberger,40% funded by the European CommunityTHERMIE project, has resulted in develop-ment of a new generation permanent gaugeand its associated components for evengreater reliability.6

Present systems are engineered specifi-cally for the permanent monitoring marketand have a life expectancy of several years(see “Hardware,” page 37).7 Gauges havedigital electronics designed for extendedexposure to high temperature and undergoextensive design qualification life tests andstrict quality checks during manufacturebefore being hermetically sealed.8 They arenot designed for maintenance.

Cables for permanent installations areencased in stainless steel or nickel alloypressure-tight tubing that is polymer-encap-sulated for added protection. All connec-tions are verified by pressure testing duringinstallation.

Connections through tubing hanger andwellhead vary depending on the type ofcompletion—subsea, platform or land—butcomponents are standard, tried and testeddesigns made in conjunction with the tub-ing hanger and wellhead manufacturers.

Data transmission and recording are tai-lored to oil company needs, and wherever

Early DaysPermanent monitoring has its roots in theearly 1960s on land wells in the USA.2 Pres-sure gauges were needed to monitor theperformance of secondary recovery pro-jects, such as waterfloods or artificial liftschemes, where they were required down-hole for several weeks. In many cases, theonly option available was to run a standardpressure gauge on the end of the comple-tion string (above). The cable for power anddata transmission was passed through aninsulated connector in the Christmas tree,strapped to the outside of the tubing andthen ported back inside the tubing justabove the gauge leaving the bore free of anyobstructions. Even though the hardware wassimple by today’s standards, these earlyexamples proved invaluable to oil compa-nies and showed the diverse use of and ben-efits from the pressure data gathered.

One example from 1962 is typical of theperiod. Henderson 6 was the second wellcompleted by the Coronado Company in theBell Sand of the Old Woman Anticline,Wyoming, USA. A permanent pressure

34 Oilfield Review

gauge was placed below a conventionalpump in a 2400-ft [720-m] well for interfer-ence testing and to determine the productiv-ity index.3 Initial bottomhole pressure (BHP)was 680 psi.

The well produced 340 barrels of oil perday (BOPD) [54 m3/d] with a 60-psi draw-down, but quickly suffered from increasingwater cut. Bottomhole pressure returned to680 psi indicating complete water break-through—possibly by water coning. Bymodifying production and monitoringdownhole pressure changes it quicklybecame apparent that the coning problemwould not repair itself and that the wellwould have to undergo workover. Afterwardthe well was put back on production and,this time, the pressure gauge measurementswere used to control drawdown to just 40psi to prevent recurrence of water coning.

Other examples from the 1960s showhow pressure gauges were used to monitorprogress of secondary recovery fronts acrossfields, to check the operation of subsurfacepumps, to provide reservoir data and to cal-culate individual well drainage during thelife of the reservoir.

nPermanent moni-toring system—circa 1960. Thepressure gaugewas hung on thebottom of the tub-ing and communi-cated with the sur-face via a cablestrapped to theoutside. Connec-tion to the gaugedownhole andrecording equip-ment at surfacewas through insu-lated ports. Thissetup causedrestrictions in flowand also preventedaccess to the wellbelow the gauge.With current per-manent monitoringsystems the gaugeis housed outsidethe tubing in amandrel allowingfullbore flow andunrestrictedaccess.

35Winter 1995

2. Nestlerode WA: “The Use of Pressure Data From Per-manently Installed Bottom Hole Pressure Gauges,”paper SPE 590, presented at the SPE Rocky MountainJoint Regional Meeting, Denver, Colorado, USA, May27-28, 1963.

3. An interference test measures the pressure response inone well to changes in production or injection in asecond well. The objective of the test is to assess com-munication between the wells.Productivity index is a measure of producibility of thereservoir and is equal to flow rate divided by pressuredrawdown.

4. Bezerra MFC, Da Silva SF and Theuveny BC: “Perma-nent Downhole Gauges: A Key to Optimize DeepseaProduction,” paper OTC 6991, presented at the 24thAnnual Offshore Technology Conference, Houston,Texas, USA, May 4-7, 1992.

5. Bezerra, Da Silva and Theuveny, reference 4.6. European Community THERMIE project on Improving

the Reliability of Permanent Down Hole PressureGauges.

7. Catherall R, Spence JR and McKee P: “PermanentDownhole Instrumentation: Recent Developments inEngineering for Reliability,” Transactions of the 3rdLatin American Petroleum Congress, Rio de Janiero,Brazil, October 18-22, 1992, paper TT-219.The life expectancy of a permanent monitoring systemdepends on many factors, the most important beingbottomhole temperature. High temperature increaseselectronic aging and failure rates. However, there arefunctioning gauges that have been in wells for morethan 10 years and these are obviously not the latesttechnology.

8. Levera R, Pohl D and Veneruso A: “PermanentGauges Enter the Digital Era,” Transactions of the 3rdLatin American Petroleum Congress, Rio de Janiero,Brazil, October 18-22, 1992, paper TT-154.

nPermanent downhole cable evolution.Standard monoconductor logging cableswere used with the first installations (1).Later, cable bumpers and polymer encap-sulation improved protection (2). In theNorth Sea there was a shift to tubing-encased cables in the mid-80s. The firsttype used Teflon insulation whichallowed the cable to slip inside the tub-ing, breaking connections (3). Teflon wasreplaced by a friction material to allevi-ate this problem (4). This type of cable isnow standard in the North Sea. Petrobrasuses a combination of tubing-encapsu-lated cables and bumpers (5).

nPermanent moni-toring system relia-bility in the NorthSea. Data onSchlumberger per-manent monitoringsystems installedin the North Sea inthe last nine yearsshows improvingreliability. Mostworking systemsare less than threeyears old (top), buta significant num-ber have beenworking longer.Most failuresoccurred duringthe first year andwere likely causedby cable or con-nection damageduring installation(middle). Ideally,systems shouldremain workingduring the life ofthe well so thataverage system lifedivided by aver-age well life equals100%. System lifereached only 54%of well life forinstallations in1988 (bottom). Thisfigure has steadilyimproved and, notsurprisingly, is100% for systemsinstalled this year.

Outer armor

Inner armor

Cable bumpers

Insulation

Central copper core

Polymerencapsulation

Outer armor

Inner armor

Insulation

Central copper conductor

Cable bumpers

Similar tocable 4

Polymerencapsulation

Stainlesssteel tubing

Inner insulation

Outer insulation

Central copper conductor

Polymerencapsulation

Polymerencapsulation

Stainlesssteel tubing

Insulation

Central copper conductor

Friction material

1 2 3 4 5

19

10

6

3

1

Age of Working Permanent Monitoring (PM) Systems

Num

ber

Years

Ave

rage

PM

life

/ave

rage

wel

l life

, %

1987 1988 1989 1990 1991 1992 1993 1994 1995

Year

Working when removed

1 2 3 4 5 6 7 8

Age of Failed PM Systems

Years1 2 3 4 5 6 7 8

Num

ber

41 21 20 5 6 3 8 3

14

1

84

1

79%

54%

70%74%

80%88% 86%

91%100%

5

12

1918

87 36

3334

mized recovery of reserves and continueddevelopment drilling.

Scapa has also seen the use of some novelhardware applications. A conventional well-head uses a dual-bore Christmas tree, whichhas to be oriented to allow the use of thetraditional wet connect system (see “Hard-ware,” next page).10 However, EEC’s con-centric completion system does not need tobe oriented. To realize the full benefits ofthis tree, EEC has successfully used aninductive coupling system at the interfacebetween the tubing hanger and the Christ-mas tree. Also, because the umbilical con-necting Scapa electrically to the Claymoreplatform has reached its capacity, data fromall the wells are stored in subsea data-log-gers. These are periodically interrogatedacoustically during one of the many trips bysupply boats to the area. Recently, the samemethod has been applied to collect datafrom flowmeters mounted on a subsea waterinjection line.

Saltire field was the next application, com-ing on stream in 1993 on the back of thePiper redevelopment. Wells were drilledfrom a minimum facility platform that would

possible industry standards are used so thatsignals may be integrated with other sys-tems. For example, many subsea comple-tions have memory modules called data-loggers that record, for instance, wellheadpressure or the status of control valves. Per-manent gauge data may be fed to interfacecards located in the data-logger so that datatransfer may be executed in one step.

Of equal importance are planning andproject management for each installation.Although most permanent monitoring hard-ware may be considered off-the-shelf, sev-eral parts may have to be customized forspecial types of wellhead. Longer lead timesmay be needed if the project requires cus-tom-built equipment. For example, in sub-sea well completions, the permanent gaugesare connected to subsea-mounted electronicpods with acoustic data links to surface.

Specialist teams of engineers and techni-cians install permanent monitoring systemsand work closely with rig crews who arefully aware of the importance of installing aworking system. Pressure gauges are usuallyconnected to the cable at the workshopwhere pressure or welded seals can easilybe made and pressure tested. At the well-site, the gauge is mounted onto a mandrel,which is connected to the tubing. The cableis supplied on a reel and is run in the holewith the tubing. Great care must be taken toavoid damaging the cable at this stage.Cable protectors placed on every tubingjoint help prevent damage as the system isrun in the well. Checks on both pressureintegrity and gauge operation during theentire procedure ensure a working system.

For certain subsea installations, hookup tosurface acquisition equipment may involvedivers and diver-matable connections orremotely operated vehicles (ROVs) and con-nections to acoustic data-loggers ortelecommunication equipment.

Once they are connected and running,permanent monitoring systems begin pay-back in many different ways as the follow-ing case studies show.

A Decade’s Experience in the North SeaElf Enterprise Caledonia Limited (EEC) hasused permanent monitoring systems in itswell completions since 1983. The first appli-cation was on Scapa, a small satellite field 5km [3 miles] from the Claymore platform inthe UK sector of the North Sea (above). TheScapa well C-47 was drilled at a highangle—67° to 68° deviation—from theClaymore platform.

A one-year extended well test (EWT) con-ducted by EEC helped determine the long-term deliverability of Scapa. Because of thedifficulties in running wireline operations insuch a high-deviation well and with theClaymore platform rig working on otherwells, it was not possible to enter C-47 dur-ing this period. The only way to obtaindownhole pressure data to evaluate theEWT was by using permanent monitoringsystems. The outcome of the EWT paved theway for the development of the field with amultiwell slot subsea template.

The second application was in the samefield, but this time in a newly discovered,lower sand body in subsea well S-20. Pres-sure data from the permanent monitoringgauges installed in this well contributed tothe estimated reserves being increased fromapproximately 40 million barrels to 60 to 70million barrels. More recently the estimatehas been increased again to 100 millionbarrels.9 Four more wells were drilled andcompleted with permanent gauges.

Permanent pressure data have been usedto model the interaction between the threeoil accumulations of the Scapa field—directly through extensive interference test-ing and indirectly through use of the data inmaterial balance and simulation studies.This has resulted in a more thorough under-standing of field behavior, leading to opti-

ClaymoreComplex

Elf Enterprise

ScapaElf Enterprise

HighlanderTexaco

PetronellaTexaco

ChanterElf Enterprise

SaltireElf EnterprisePiper B

Elf Enterprise

AberdeenPeterhead

St. Fergus

Flotta terminal

MCP01

TartanTexaco

SCOTLAND

Orkney Islands

Gas pipelineOil pipeline

Ivanhoe/Rob RoyAmerada Hess

n Location of Scapa, Saltire and Chanter fields. (Courtesy of Elf Enterprise Caledonia Ltd.)

36 Oilfield Review

9. Ellison RL, Simlote VN and Ko RS: “ContinuedDevelopment, Reservoir Management and ReservoirModelling Have Increased Proven Developed OilReserves by Over 35% in the Marginal Scapa Field,”paper SPE 25063, presented at the SPE EuropeanPetroleum Conference, Cannes, France, November16-18, 1992.

10. A wet connect is an electrical connector—a plugand socket—that is pressure-tight and waterproof. Itallows a connection to be made in any fluid underhigh-pressure and over a range of temperatures. Awiper system cleans the male pin as it is insertedinto the female socket ensuring good electrical con-tact. O-rings prevent fluid entry as the connection ismade, ensuring insulation.

(continued on page 41)

Pressure Gauges

Pressure gauges are built to more exacting life-

time specifications than wireline- or drillstem

test-conveyed systems. A temporary completion

may contain gauges that stay downhole for sev-

eral months during a long-duration well test.

However, permanent gauges have to stay in wells

for several years. Reliability is a key feature and

this is inversely proportional to temperature,

time and wellbore chemistry. Gauge electronics

are designed with this in mind.

Schlumberger permanent gauges use a modi-

fied version of UNIGAGE electronics. These elec-

tronics are used in Schlumberger memory gauge

recorders and are designed for rugged, long-

duration operations. Modifications include opting

for totally soldered and hermetically sealed,

solid-state electronic components that may be

bigger or more expensive, but are temperature-

stable for long periods. Any drift in the electron-

ics is automatically corrected. Once installed, the

gauges are not going to be used on other wells,

so there is no need to consider maintenance. To

this end, all internal connectors and sockets are

eliminated and, after 100% burn-in and calibra-

tion testing, the gauge housings are welded shut

during manufacture. Connections to the outside

are provided by a feed-through connector (right).Sensors used in permanent gauges have

slightly different specifications than pressure

gauges used in well testing. The emphasis is on

long-term gauge stability rather than fast

dynamic response. Quartz crystals are most often

used although other types of sensor, such as sap-

phire sensors, may also be used.

■■Permanent quartz gauge. The permanent quartzgauge measures downhole temperature and pres-sure. High measurement stability and long life areachieved by using hermetically sealed quartz crystalresonators, digital electronics and proprietarymechanical seals.

Pressure connection

or

Digital pressure,temperature and self-test

1⁄4-in. encased cable

Cable driver andfault-tolerant regulator

Metal-to-metal sealedcable head

Hermetically sealedwelded housing

Autoclave AxialConnection

Gland RadialConnection

Quartz crystal resonatorsmeasure pressureand temperature

Protection bellows

…11

010

P/T

37Winter 1995

A permanent gauge installation is an engineered

product tailored to the well completion. The sys-

tem is built of standard components carefully

chosen to fit oil company requirements. The com-

plete system ranges from pressure gauge to

cable, from wellhead to data transmission.

Hardware

Gauge Mandrel

Gauges are housed in the protective recess of a

gauge mandrel (above). This provides complete

gauge protection against mechanical damage

along the entire gauge length. Gauge protection

is especially important in deviated wells, where

the gauge has to pass through liner hangers, or

during completions from floating vessels.

Bottomhole Connectors

There are two connections to the permanent

gauge: electrical connection to the cable for

power and data transfer, and hydraulic to connect

the sensor to tubing pressure. Electrical connec-

tion is usually made at the workshop. The con-

ductor is soldered to the feed-through connector.

The pressure connection is made at the wellsite

with metal-to-metal seals.

Metal-to-metal seals are also made between

the gauge and its gauge carrier or gauge man-

drel. At the wellhead end of the cable, metal-to-

metal seals are again made to ensure that con-

nections are pressure tight. Each connection is

pressure tested and verified during installation

at the wellsite.

Cable

Cables form a major part of the budget for a per-

manent monitoring system—up to 30% of the

cost. Permanent downhole cables have to with-

stand pressure, temperature and exposure to

highly corrosive wellbore fluids during the life of

the permanent installation. They also have to be

mechanically rugged so that they are not dam-

aged during installation. Cables consist of copper

conductors surrounded by Teflon insulation mate-

rial, antislip filler, standard 1/4-in. stainless-

steel or nickel alloy tube and thermoplastic

encapsulation material (page 35, top).1 The filler

material supports the cable inside the tube pre-

venting the entire weight of the cable from being

supported by the top connector. It also allows

38 Oilfield Review

Section A-A

Cable head

Permanent gauge

Exploded view ofmetal-to-metal seal

A A

Tubinghanger

Threaded wellhead outlet

Cable penetratorwith sealingglands ateach end

Optional flanged wellhead outlet

■■Gauge mandrel. The gauge mandrel provides aprotective recess for the permanent gauge.

■■Surface wellhead con-nector. Signals from thepermanent downholegauge pass from thecable, clamped to theoutside of the tubing, toan external terminal onthe wellhead. Holes aremade in the tubinghanger and wellhead todo this. Threaded con-nections are made oneach, so that compres-sion fittings can sealeach side of the holes to maintain pressureintegrity of the wellhead.

some movement inside the stainless-steel tube so

that the cable is not exposed to thermal stresses.

The metal tube has up to 20,000-psi collapse

pressure and prevents wellbore fluid contamina-

tion which could short circuit the insulation.

Encapsulation helps prevent cable damage such as

nicks and crimping during installation. Even so,

the cable requires careful handling.

Cables usually have single conductors, but can

be manufactured with more. Encapsulation materi-

als and sizes can also be tailored to oil company

requirements.

Cable Protectors

Cables are clamped to the tubing string using

cable protectors. These are clamped across tubing

joints—the place where the cable flexes slightly

over the collar (above right).

Tophole Connectors

Connections are made by pressure-tight, compres-

sion-fit, metal-to-metal seals between the down-

hole cable and the tubing hanger and downhole

cable and gauge. Other elements of the comple-

tion may also require connections, for example, if

the cable has to pass through a packer.

Wellhead Connectors

There are many types of wellheads and the cable

from a downhole permanent gauge must pass

through to an exterior terminal. Connections are

first made to the tubing hanger. Connections to the

other side of the hanger depend on the type of

wellhead. If the wellhead is at surface—for exam-

ple, a wellhead on a land well or a wellhead

exposed above the sea on a platform—then a con-

nection has to be made through the wellhead to a

terminal block (previous page, bottom). The signal

is then routed to the surface acquisition system.

For subsea wellheads, the connection is more

complicated (right). An electric wet-connect (EWC)

system is commonly used enabling a direct link

across the wellhead. The EWC consists of a male

pin situated in the tubing hanger. The female

socket sits below the valve block and is oriented to

align with the male pin. On the outside of the well-

head valve block is a flanged outlet to either a

diver-matable subsea electrical connection or a

remote-operated vehicle connection. The signal

is then routed to an acoustic transducer, an inte-

grated control pod or a subsea umbilical.

Acquisition Systems

There are a number of different methods for col-

lecting data. Often on subsea completions, it is

possible to hook into existing data-gathering sys-

tems. These have been set up to monitor subsea

wellheads providing such data as surface flow

rates, temperature and pressure as well as valve

positions and status. Permanent gauge interface

cards are now available for most data gatherers,

which are normally connected to platforms by

seabed umbilical cables.

A system that does not use an umbilical cable

is a hydro-acoustic system (next page). In this

approach, the permanent gauge signal is col-

lected at a data acquisition unit (DAU) that logs

and performs a quality check of each measure-

ment. The DAU can be periodically interrogated

39Winter 1995

1. Much has been published about the potential of fiber-optic cables. For an operator’s perspective of where thistechnology currently stands:Botto G, Maggioni B and Schenato A: “Electronic, Fiber-Optic Technology: Future Options for Permanent Reser-voir Monitoring,” paper SPE 28484, presented at the 69thSPE Annual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 25-28, 1994.

Tubing joint

Standard designProtectorfor twin

encapsulatedcable

Cross-Coupling Cable Protectors

Diver-matable subseaelectric connection

Flanged wellhead outlet

Female wet-connect

Male wet-connect

Tubing hanger

1⁄4-in. encased cable

Wellheadvalve block

■■Permanent cable protector.

■■Subsea wellhead connectors. Signals have to passthrough the tubing hanger and Christmas tree toemerge at a suitable connection—diver or ROV mat-able. A male electrical wet-connect makes the con-nection through the tubing hanger to the permanentdownhole cable. The wellhead valve block is pre-pared with a flanged outlet and female wet-connect.Contact is made when the oriented wellhead is low-ered onto the tubing hanger.

using an acoustic transducer that may be hung

over the side of a boat, rig, platform or even from

a helicopter. The subsea equipment is powered by

a battery pack that can be replaced by divers or a

ROV without losing the DAU memory.

For platforms, several permanent gauges may

be connected to an autonomous surface unit that

is rack-mounted in the cabin or packaged in an

explosion-proof box near the wellhead. This

acquires and records the raw measurements and

communicates with the oil company’s computers

via standard modem data links or local area net-

works. Communication may be via satellite to the

oil company office anywhere in the world.

Software

Permanent gauge monitoring software enables a

user to control and monitor permanent gauges

from anywhere in the world. This Windows-based

PC software makes full use of standard communi-

cations networks and straightforward point and

click menus and icons. With this software, a user

can view the real-time downhole gauge measure-

ments directly or display recorded data files. In

addition, the data can be shared via networks with

other users for further analysis and interpretation.

Power Supply

Gauge power is provided from surface directly

from subsea umbilicals, platform supplies or from

subsea battery packs. On land in sunny areas,

batteries may be recharged using solar panels.

40 Oilfield Review

■■Acoustic data link. In subsea completions signals may be stored in abattery-powered data acquisition unit (DAU). The DAU communicatesacoustically with the surface using a remote transducer. The trans-ducer may be hung over the side of a rig or supply boat or even hungbeneath a helicopter.

Surfacetransducer

Remotetransducers

Subsea wellhead

Data acquisition unit (DAU)

Battery pack

PC-controlledsurface interrogation system

not allow concurrent well intervention dur-ing a drilling program lasting several years.When drilling stopped, the platform wouldbecome unmanned. Any well reentry fordata gathering would then be extremelycostly. So EEC decided to incorporate perma-nent monitoring systems in the completionsfrom the first stages of field development.

The reservoir proved to be complex andpermanent pressure data served to optimizeproduction (below). For example, the bub-blepoint of the crude oil in one of the reser-voir members is 3700 psi and the initial for-mation pressure, 4600 psi. So drawdownhad to be less than 900 psi to sustain gas-free production. High skin factor in the firstwell meant that as large a drawdown as pos-sible would be needed for adequate produc-tion—introducing a further complication.However, the pressure could be carefullymonitored and production optimized tomaintain reservoir pressure at around 40 psiabove bubblepoint.

Additional benefits of continuous pressurerecording have included cross-field interfer-ence testing that has shown that althoughthe reservoir is mapped as being compart-mentalized, there is generally pressure com-munication between compartments. Forexample, pressure changes of less than 5 psiare detected in a well approximately 600 m[2000 ft] away from one being pulsed(right ). These data helped optimize welllocations and water injection strategy tomaintain reservoir pressure, and have alsoprovided a useful history-matching parame-ter for the reservoir simulator model.

41Winter 1995

nInterference test. Pressure pulses recorded in Saltire A01 (top) are seen as smallchanges in pressure recorded by the permanent gauge in Saltire A04 (bottom). (Courtesyof Elf Enterprise Caledonia Ltd.)

n Permanent pres-sure data used tooptimize production.Production from oneof the Saltire reser-voir members wasadjusted severaltimes until anacceptable bottom-hole flowing pres-sure was achievedin Well A07. Abruptchanges in pressuremay be seen eachtime the productionwas adjusted. (Cour-tesy of Elf EnterpriseCaledonia Ltd.)

Saltire A01

Saltire A04

4900

4800

4700

4600

4500

4400

4300

4200

4100

4000

13 14 15 16 17 18 19 20 21 22 23 24 25June

Pre

ssur

e, p

si

Pressure pulses

Effect ofshort pulses

5060

5040

5020

5000

4980

4960

Effect oflong pulse

Pre

ssur

e, p

si

2960

2940

2920

2900

2880

2860

2840

2820

2800

2780

18 23 28 02 07 12 17 22 27 31 05 10 15 20 25 30 05

July August September

Pre

ssur

e, p

si

Well A07

Adjustments in production

A more unusual use of permanent pres-sure data confirms the successful isolationof an underlying higher pressure intervalthat would otherwise have been difficult todemonstrate (below).

The final EEC field application is on a sin-gle subsea well development—the Chanterfield. This has separate reservoirs of oil andcondensate. Initially the well produced oiland was later converted to produce conden-sate. Continuous pressure monitoring keptreservoir pressure from dropping below oilbubblepoint during that particular phase ofproduction and also helped optimize the tim-ing of conversion to a condensate producer.

The pressure data also provided input tocalculate the accumulation in contact withthe well and evaluate the effectiveness ofthe aquifer as a reservoir drive mechanism.This information will help establish the

requirement for a possible additional well inthe field. In subsea wells such as Chanter,the cost of the permanent monitoring systemis immediately recouped if only one wellreentry operation is avoided.

Apart from the major applicationsdescribed above, EEC has also found perma-nent monitoring data useful in other circum-stances. Knowing bottomhole pressureallows calculating the correct weight of killfluid. This minimizes formation damagewhile ensuring an effective kill. Knowledgeof bottomhole pressure also allows optimalcontrol of underbalanced perforating.

Based on their experience in the NorthSea, EEC considers permanent monitoringsystems beneficial whenever developmentinvolves satellite fields, subsea completions,difficult access well completions or limitedaccess platforms.

Norwegian ConnectionTwo fields in the Norwegian sector of theNorth Sea highlight several more applica-tions of pressure data recorded by perma-nent monitoring systems.11 Gullfaks andVeslefrikk fields operated by Statoil are com-plex and require careful reservoir manage-ment. Gullfaks is in the central part of theEast Shetland basin, 175 km [109 miles]northwest of Bergen, Norway. Veslefrikk isabout 30 km [19 miles] south of Gullfaks(next page, top).

Gullfaks is heavily faulted with a numberof sealing or partially sealing faults. Oneimportant reservoir monitoring objective isto measure the degree of communicationbetween the fault blocks. Veslefrikk startedproduction with commingled wells. Heregauges are used in dedicated wells to moni-tor the two reservoirs independently. Dataare used in both fields to ensure single-phase oil flow in each fault block, to moni-tor and optimize well performance withtime, for transient well test analysis and formatching numerical models.

At present, Statoil has more than 50 per-manent gauge installations. Each is con-nected to a communications system thatallows gauge control from PCs located any-where in the world. For example, a well testcan be monitored remotely and the datasampling rate adjusted during the test.

Gullfaks—Gullfaks field development isbased on single-phase oil flow without free-gas in the reservoir. In wells with permanentmonitoring systems, bottomhole flowingpressure (BHFP) is maintained slightly abovesaturation pressure by adjusting the flow rate(next page, bottom).12 This results in a poten-tial increase in the individual well productionrate of 100 m3/d to 500 m3/d [630 B/D to3150 B/D]. In wells without permanent mon-itoring, calibrated curves based on empiricalmultiphase equations and permanent pres-sure data from nearby wells are used.

42 Oilfield Review

Time, hr

4500

4400

4300

4200

4100

4000

3900

3800

37000 12 24 36 48

Piper perforated

Confirmation ofisolation

Galley backon production

Pre

ssur

e, p

si

Piper plugged

Galley zone shut-in

Well shut-in;pressure increasesduring crossflow

11. Schmidt H, Stright DH and Forcade KC: “MultiwellData Acquisition for Permanent Bottomhole PressureGauge Installations,” paper SPE 16511, presented atthe Petroleum Industry Applications of Microcom-puters, Montgomery, Texas, USA, June 23-26,1987.Unneland T and Haugland T: “Permanent DownholeGauges Used in Reservoir Management of ComplexNorth Sea Oil Fields,” SPE Production & Facilities 9,no. 3 (August 1994): 195-203; also paper SPE26781, presented at the SPE Offshore Europe Con-ference, Aberdeen, Scotland, September 7-10, 1993.

12. Statoil has looked into the effects of producing

below bubblepoint in the near wellbore region.13. Unneland T and Waage RI: “Experience and Evalua-

tion of Production Through High-Rate Gravel-PackedOil Wells, Gullfaks Field, North Sea,” SPE Produc-tion & Facilities 8, no. 2 (May 1993): 108-116; alsopaper SPE 22795, presented at the SPE Annual Tech-nical Conference and Exhibition, Dallas, Texas,USA, October 6-9, 1991.

14. Bale A, Owren K and Smith MB: “Propped Fractur-

ing as a Tool for Sand Control and Reservoir Man-agement,” paper SPE 24992, presented at the Euro-pean Petroleum Conference, Cannes, France,November 16-18, 1992.Bale A, Smith MB and Settari A: “Post-Frac Produc-tivity Calculation for Complex Reservoir/FractureGeometry,” paper SPE 28919, presented at the SPEEuropean Petroleum Conference, London, England,October 25-27, 1994.

nIsolation of a high-pressure interval. Pressure data recorded in Saltire A04 shows atypical buildup when the Galley sandstone is shut in prior to perforating the Pipersandstone. Pressure increases rapidly when the high-pressure Piper zone is perforated.A bridge plug is set to isolate Piper and this is confirmed as successful by the return tothe original shut-in pressure buildup trend of the Galley zone. (Courtesy of Elf EnterpriseCaledonia Ltd.)

Data from permanent gauges are used tohistory match numerical models for eachproduction area, to identify the degree ofcommunication between wells and to con-trol the flow into and out of each block tomaintain material balance. For example,geological interpretation indicated a faultbetween two wells—a producer and aninjector. The producer was shut in duringstart of injection. Permanent gauge datafrom the producer showed an increase inpressure during this start-up period indicat-ing excellent communication across thefault. Combining openhole pressure dataand permanent pressure data has revealedsuch interwell communication in a numberof wells.

About 40% of Gullfaks producers aregravel packed and contribute more than50% of production.13 In the majority ofthese wells, permanent gauges continuouslymonitor downhole flowing pressure andtemperature. These data provide input tomonitor gravel-pack performance and maybe used to analyze and identify problemscaused by a variety of phenomena, includ-ing migration of fines and scales.

As an alternative to gravel packing forsand control, Statoil has used indirect verti-cal fracturing to complete several wells.14

This method allows production from uncon-solidated sands through less productive,fractured, consolidated intervals. Availabilityof real-time downhole pressure data allowsfracturing operations to be optimized and,for operational reasons, these data can beobtained only from permanently installedmonitoring systems.

43Winter 1995

1000 1500 2000 2500 3000 3500 4000 4500Time, hr

Flow

rat

e, m

3 /d

2

500

3000

Pre

ssur

e, k

Pa

27,

000

28,0

00

Bergen

PC Modemtelephone

Gullfaks

Veslefrikk

Permanentgauge

Murchison

Huldra

Statfjord

Gullfaks South

Veslefrikk

Snorre

Alwun

Brent

Gullfaks

Norway

Denmark

Germany

nAdjusting bottom-hole flowing pres-sure (BHFP) tomaximize oil pro-duction. As BHFP isadjusted to slightlyabove saturationpressure on Gull-faks C-3 (top), dailyoil production rateincreases (bottom).(Adapted fromUnneland and Haug-land, reference 11.)

nLocation and permanent monitoring system setup of Gullfaks and Veslefrikk fields.(Adapted from Unneland and Haugland, reference 11.)

Even though permanent sensors weredeployed several tens of meters above perfo-rations, transient analysis of their pressuredata gave satisfactory results when com-pared to data from wireline pressure gaugeslocated much closer to producing zones. Inthis example, the wellbore storage effect didnot dominate transient analysis, whichallowed a comparison of results. Differencesin calculated values of skin were attributedto frictional losses along the tubing to thepermanent gauge. This allowed correctionsto be made to other permanent gauge datasets in the area to estimate true formationskin (right).

Gullfaks produces from a mixture of weakformations and exhibits large variations indepletion in the various fault blocks andreservoirs. In many cases, only a small mar-gin exists between formation fracture pres-sure and pore pressure. Safe drillingdepends on obtaining an estimate of porepressure for each zone before penetratingthe reservoir. Permanent pressure data areused to calculate pore pressure and hencedetermine the optimum mud weight for wellcontrol without fracturing the formation.

Veslefrikk—The 12,000-m3/d [75,000-B/D] Veslefrikk field, located 145 km [90miles] northwest of Bergen, was considereda marginal field. To reduce total investment,commingled production and injection wasplanned from the Brent and Intra DunlinSand (IDS) reservoirs. Control is obtained byselective perforation in producers anddownhole chokes in injectors. A carefullyplanned data acquisition program duringthe initial production phase provided infor-mation about reservoir properties, produc-tion potential and well behavior. In addi-tion, two of the largest uncertainties werepartially resolved: the degree of communi-cation across the main arcuate fault and thevertical transmissibility between the Lowerand Middle Brent through the low-qualityRannoch sand.

This information led to improved reservoirdescription and allowed adjustments to be

44 Oilfield Review

Comparison of Raw Data

Wireline gauge data

Effects of phase segregation atdepth of permanent gauge

24,0

0025

,000

26,0

0027

,000

Per

man

ent p

ress

ure,

kP

a

Permanentgauge data

Wire

line

pres

sure

, kP

a27

,000

28,0

0029

,000

30,0

00

Wel

lbor

e pr

essu

re, k

Pa

24,5

0025

,000

25,5

0026

,000

26,5

00W

ellb

ore

pres

sure

, kP

a27

,500

28,0

0028

,500

29,0

00

By visual fitp = 26086.051 kPam = 271.685 kPakh = 17.1477 µm2.ms = - 0.87 storage units

By least squaresp = 29116.602 kPam = 271.685 kPakh = 17.1477 µm2.ms = - 2.04 storage units

Interpretation of Wireline Pressure Data

Interpretation of Permanent Pressure Data

-5 -4 -3 -2 -1 0Multiple-rate Horner time

-5 -4 -3 -2 -1 0Multiple-rate Horner time

0 4 8 12 16 20 0 4 8 12 16Time, hr

nComparisonbetween permanentand wireline gaugepressure data. OnGullfaks A-10buildup pressuredata were recordedby a wireline pres-sure gauge set closeto the perforationsand also by the per-manent gauge (top).The permanentpressure data showthe effects of phasesegregation, butdespite this bothdata sets may beused for analysis(middle and bottom).The difference incalculated skin, s,in the analysis ofthe two data sets isattributable to fric-tion pressure lossbetween the perfo-rated interval andthe permanentgauge. (Adapted fromUnneland and Haug-land, reference 11.)

made to the reservoir development planbefore drilling the first injection well. A full-field numerical model was constructed,enabling careful planning and effectivereservoir management. Permanent gaugedata play a vital role for continuous historymatching and refinement of this model.

History matching has shown that lateralcommunication across the IDS reservoir isconsiderably more complex than describedby the geological model. This complexityhas been attributed to lateral changes inlithology.

Permanent gauges were run in dedicatedIDS wells. A falloff analysis showed that oneproducer was isolated on three sides fromwells farther south and that communicationto an injector across the main arcuate faulton the fourth side was unexpectedly good.This information allowed the injection rate tobe decreased and the production rateincreased until the pressure balancedbetween the two. This resulted in an increasein production of 200 m3/d [1260 B/D].

Gauge Drift—To monitor permanentgauge performance over time, Statoil hascompared permanent gauge pressure datawith data from wireline pressure gauges(next page). A radioactive marker installedin the permanent gauge mandrel allowsaccurate depth control of the wirelinegauges run during periodic production log-ging operations. Several comparisons havebeen made in the same wells over severalyears and no significant drift has beenobserved on any of the gauges.

Permanent monitoring systems are consid-ered a good investment by Statoil and instal-lations have recently been made in severalsatellite fields around Statfjord and Sleipner,with plans to install gauges on the Heidronplatform.

45

nApplications andbenefits of perma-nent monitoringsystems.

Reservoir Management ApplicationsApplication

Interference testing

Reservoir pressure control

Transient well testing

History matching

Well performance

Hydraulic fracturing

Bottomhole pressure data

Description

Establishes the degree of commu-nication across the field, betweenwells, between fault blocks and also the vertical transmissibilitybetween reservoirs.

Maintains bottomhole flowing pressure above a threshold bymonitoring permanent gauge datawhile adjusting water or gas injec-tion, or while varying production.

Performs a pressure buildup testautomatically whenever a well containing a permanent gauge is either deliberately or inadver-tently shut-in. Similarly a pressuredrawdown test is performed whenthe well is opened up.

Provides continuous recording ofpressure data during the lifetime of the well.

Provides continuous recording ofpressure data.

Monitors downhole pressure duringhydraulic fracturing.

Provides continuous knowledge of bottomhole pressure.

Benefits

• Wireline intervention eliminated.• Limited planning involved.• Observation of effects caused

by any change in production orinjection in wells where perma-nent gauges are installed.

• Individual well production maximized.

• Injection rates optimized.• Sand production eliminated by

controlling drawdown.• Completion costs optimized.

• Transient analysis of problemwells with minimum intervention.

• Real-time, early reservoir datawith no cable in the tubingduring an extended well test orduring early production.

• Remote control and analysisof data.

• Limited production loss byeliminating wireline operations.

• Verification or adjustment ofreservoir models.

• Improved reservoir description.• Improved estimation of reserves.

• Completion performance established.

• Gravel-pack performanceestablished.

• Monitoring of migration of fines or scale buildup.

• Wellbore hydraulic curves calibrated for optimizing gas lift.

• Fracture length optimized.• Real-time surface readout of

downhole pressure data during a frac.

• Pore pressure calculated for safety while drilling developmentwells.

• Computation of accurate kill fluidweight.

• Calculation of accurate under-balance or over-balance beforeperforating.

Field or Well Condition ApplicationsApplication

Restricted access

Highly deviated wells

Pumping wells

Description

Installs permanent monitoring sys-tems whenever access is restrictedby subsea completion wells, smallplatforms or single wells, remoteland wells or when other activitieson a platform, such as continuousdrilling, prevent well access.

Installs permanent monitoring sys-tem with completion.

Runs gauges to monitor pumpinlet pressure and pump outletpressure.

Benefits

• Elimination of costs associatedwith wireline intervention.

• Operational hazards reduced.• No personnel required.• No rig required.• Only method to record data in

many cases.

• Elimination of costs of coiled tubing or snubbing equipment to convey wireline pressure gauges.

• Pump efficiency established.• Pump rate optimized.• Pump maintenance planned.• Only practical method to record

downhole pressure data.

Multisensor ApplicationsAll the applications described above requireonly one permanent downhole pressuregauge—even though in some cases a secondgauge has been used for redundancy. Thereare many other applications for permanentmonitoring systems and some require morethan one sensor (previous page).

Many oil companies have wells equippedwith electrical submersible pumps that areimpractical to log by wireline methods.15 Asingle permanent pressure gauge may provide useful information about well orreservoir performance, recording formationpressure when pumps are switched off.However, monitoring pressure during pump-ing—at the pump inlet and outlet—providesadditional information about pump effi-ciency. Pump efficiency has an impact not

only on production, but also on pump lifeand workover schedules. Tracking pump per-formance and adjusting pump speed tomatch reservoir conditions increase effi-ciency and pump life.

A relatively new technique uses perma-nent pressure gauges and a venturi to moni-tor downhole flow rates.16 A venturi isessentially a restriction placed in a flow-line—in this case the tubing. The venturicauses a small change in pressure—typi-cally less than 10 psi—which is related tothe fluid velocity. Often three pressuregauges are used, two for the venturi—tomeasure differential pressure—and the thirdone for standard pressure measurementssome distance away from the other two, sothat fluid density may also be calculated.

A Permanent Seat in Completion Plans?Driven by the trend toward unmanned plat-forms, subsea completions, limited accesswells—either because of their remote loca-tion on land, top-side activity offshore orwell deviation in general—permanent moni-toring systems are becoming an establishedpart of well completions. Now that reliabilityissues have been resolved by sound projectmanagement and the introduction of newtechnology, permanent monitoring systemsare a proven cost-effective and safer alterna-tive to intrusive data acquisition methods.

Applications for pressure data gathered bypermanent monitoring systems are numer-ous, ranging from reservoir evaluation dur-ing extended well tests or early in the pro-duction cycle, to lifetime reservoir and wellmanagement. Modern communication sys-tems enable remote control of the sensorsand make the data accessible from officesanywhere in the world, increasing the valueof permanent monitoring systems. —AM

46 Oilfield Review

15. Kilvington LJ and Gallivan JD, “Beatrice Field: Elec-trical Submersible Pump and Reservoir Performance1981-83,” Journal of Petroleum Technology 36(November 1984): 1934-1940; also paper SPE11881, presented at the Offshore Europe 83 Confer-ence, Aberdeen, Scotland, September 6-9, 1983.Gallivan JD, Kilvington LJ and Shere AJ: “ExperienceWith Permanent Bottomhole Pressure/TemperatureGauges in a North Sea Oil Field,” paper SPE 13988,presented at the Offshore Europe Conference 85,Aberdeen, Scotland, September 10-13, 1985.

16. Brodie AD, Allan JC and Hill G: “Operating Experi-ence With ESPs and Permanent Downhole Flowme-ters in Wytch Farm Extended-Reach Wells,” Journalof Petroleum Technology 47, no. 10 (October 1995):902-906.

150

100

50

0

-50

-100

-150

Pre

ssur

e di

ffere

nce,

kP

a

21,500

Permanent gauge pressure, kPa23,500 25,500 27,500 29,500

System 1System 2System 3

nPermanent gauge drift. Whenever wireline pressure gauges havebeen used in wells with permanent gauges installed, gauge drift maybe measured. Radioactive markers help avoid depth mismatch errorsenabling a good comparison. Results show that differences in mostcases are acceptable especially when gauge accuracy is taken intoaccount. Data presented are from gauges installed by three compa-nies. The discrepancy for System 3 is believed to be caused by wire-line gauge error rather than permanent gauge drift. (Adapted fromUnneland and Haugland, reference 11.)