It is human nature to seek to experience the inac- cessible. The planet Mars fascinates us, but its remoteness, cold temperatures and thin atmo- sphere preclude a visit by humans for the time being. Just as it is difficult to study Mars first- hand, we cannot directly view all the compli- cated interactions within a hydrocarbon reservoir from the Earth’s surface. In the case of the faraway planet Mars, the special Sojourner rover explored places humans couldn’t. Removing enough rock from a wellbore to accommodate a human would be prohibitively expensive, so we have traditionally used tools conveyed by wireline, coiled tubing or drillpipe during or after well construction to measure and record what we can’t see ourselves. 18 Oilfield Review Controlling Reservoirs from Afar John Algeroy A.J. Morris Mark Stracke Rosharon, Texas, USA François Auzerais Ian Bryant Bhavani Raghuraman Ruben Rathnasingham Ridgefield, Connecticut, USA John Davies Huawen Gai BP Amoco plc Poole, England Orjan Johannessen Norsk Hydro Stavanger, Norway Odd Malde Jarle Toekje Stavanger, Norway Paul Newberry Lasalle Project Management Poole, England For help in preparation of this article, thanks to Joe Eck, Houston, Texas, USA; Stephane Hiron and Younes Jalali, Clamart, France; and Mike Johnson, David Malone and Tony Veneruso, Rosharon, Texas. ECLIPSE, TRFC-E (electric tubing-retrievable flow-control valve), Variable Window and WRFC-H (hydraulic wireline- retrievable flow-control valve) are marks of Schlumberger. Understanding reservoir behavior is difficult enough; controlling it is an even greater challenge. New, remotely operated flow-control technology is helping make full use of reservoir knowledge and increasing production efficiency.
Transcript
It is human nature to seek to experience the inac-cessible. The planet Mars fascinates us, but itsremoteness, cold temperatures and thin atmo-sphere preclude a visit by humans for the timebeing. Just as it is difficult to study Mars first-hand, we cannot directly view all the compli-cated interactions within a hydrocarbon reservoirfrom the Earth’s surface.
In the case of the faraway planet Mars, thespecial Sojourner rover explored places humanscouldn’t. Removing enough rock from a wellboreto accommodate a human would be prohibitivelyexpensive, so we have traditionally used toolsconveyed by wireline, coiled tubing or drillpipeduring or after well construction to measure andrecord what we can’t see ourselves.
18 Oilfield Review
Controlling Reservoirs from Afar
John AlgeroyA.J. MorrisMark StrackeRosharon, Texas, USA
François AuzeraisIan BryantBhavani RaghuramanRuben RathnasinghamRidgefield, Connecticut, USA
John DaviesHuawen GaiBP Amoco plcPoole, England
Orjan JohannessenNorsk HydroStavanger, Norway
Odd MaldeJarle ToekjeStavanger, Norway
Paul NewberryLasalle Project ManagementPoole, England
For help in preparation of this article, thanks to Joe Eck,Houston, Texas, USA; Stephane Hiron and Younes Jalali,Clamart, France; and Mike Johnson, David Malone andTony Veneruso, Rosharon, Texas.ECLIPSE, TRFC-E (electric tubing-retrievable flow-controlvalve), Variable Window and WRFC-H (hydraulic wireline-retrievable flow-control valve) are marks of Schlumberger.
Understanding reservoir behavior is difficult enough; controlling it is an even
greater challenge. New, remotely operated flow-control technology is helping
make full use of reservoir knowledge and increasing production efficiency.
Autumn 1999 19
For a hydrocarbon reservoir, it is not just amatter of satisfying our natural curiosity, though.It is an economic imperative to understand andcontrol what is happening in the reservoirbecause ignorance can be very costly. For exam-ple, significant reserves may be lost to us foreverif water bypasses the hydrocarbons and breaksthrough into a producing well. In addition, fluids inthe reservoir might not be flowing where we wantor expect them to flow, especially in complexdevelopments featuring multilateral wells andcompletions in multiple pay zones.
Fortunately, we are now able to deploy down-hole completion devices that allow us to not onlymonitor the well from the surface, but alsoremotely control flow from specific zones into thewell and production tubing. As wells produce fluidfrom reservoirs, downhole sensors gather real-time or near real-time measurements that can beinput to computer programs that help analyze thereservoir and production operations. Engineerscan then determine how to adjust downholevalves to optimize production.
Through these advances in completion tech-nology, the industry can increase or acceleraterecovery from reservoirs while minimizing risks,lifting costs and expensive well interventions. Inthis article, we examine downhole measurementand control solutions that optimize production andreserve recovery.
The Complete PictureThe goal of any well completion is to safely,efficiently and economically produce fluids fromthe reservoir and bring them to the surface.1
While drilling a well to the desired depth mightseem like an end in itself, there are many moreoperations and decisions that precede productionfrom the wellbore (right). Casing or other tubularsmust be designed, selected and installed in thehole along with any tools and equipment neededto convey, pump or control production or injec-tion of fluids. Completion integrity depends on a good cement job or else the completion iscompromised from the start. Of course, thecompletion design must address reservoir type,drive mechanism, fluid properties, well config-uration and any complications that might exist,such as sand production or paraffin deposition,for example (next page).
> Steps toward well completion and optimized production.
1. For information on well completions: Economides MJ,Dunn-Norman S, Watters LT: Petroleum WellConstruction. New York, New York, USA: John Wiley and Sons, 1998.Hall LW: Petroleum Production Operations. Austin, Texas, USA: Petroleum Extension Service of The University of Texas at Austin, 1986.Van Dyke K: A Primer of Oilwell Service, Workover, and Completion. Austin, Texas, USA: Petroleum Extension Service of The University of Texas at Austin in cooperation with Association of Energy Service Companies, 1997.
Remote areasOnshore or offshoreDeepwater or subsea
Reservoir fluids
GasOilWater
Completion practices
> Completion considerations. All aspects of the reservoir and well must enter into completion design.
Sensors Actuators IntelligentCompletion
Software
> Elements of an intelligent completion.
Standard completion technology—cementingcasing in the borehole, installing production tub-ing, packers and other production equipment, andthen perforating zones of interest to allow flowfrom the reservoir to the wellhead—has bene-fited the industry for decades. Moving forwardinto new operating environments and more com-plicated well designs requires better ways tooptimize production from wells without risky orpossibly ill-timed mechanical intervention.Surface intervention can be extremely difficult.Deepwater or subsea well intervention is oftenexpensive.2 Completion technology that relies onsurface flow-control valves alone precludesselective production from multiple flow units in asingle wellbore or one lateral of a multilateralwell. In the past, this has resulted in an inabilityto control production from commingled flow units,crossflow or suboptimal production. The lack ofdownhole flow-control technology can delay pro-duction and negatively affect net present value ifeach zone is produced sequentially.3
The absence of downhole monitoring devicesin traditional “dumb iron” completions, whichmake up the vast majority of completions, resultsin limited reservoir data. Total flow rate, well-head pressure and fluid composition might beknown from surface measurements, but theactual conditions in a producing zone and thecontributions of individual zones cannot beknown with certainty unless “smart” measure-ment devices downhole provide a more completeunderstanding of what each part of a wellborecontributes. Other options, such as well testingand production logging, provide data from dis-crete points in time, rather than a continuous his-tory. They present costs and risks, a key riskbeing the fact that a well test requires interrup-tion of production.
No matter what completion technology andpractices are used, reservoirs behave in unex-pected ways, particularly new reservoirs aboutwhich little is known. The ability to adjust down-hole equipment in response to real-time datamakes production surprises less worrisome. Thefirst installation of an intelligent completion, bySaga Petroleum in August 1997, initiated aninteractive phase in production optimization.4
Two years later, fewer than 20 advanced comple-tions exist around the world, but they areincreasing reserve recovery and proving theireconomic and operational worth.
Advanced Completion TechnologyThe design goal for intelligent completiondevices is safe, reliable integration of zonal iso-lation, flow control, artificial lift, permanent mon-itoring and sand control. An intelligentcompletion is defined as one that provides theability to both monitor and control at least onezone of a reservoir (below).5 There are manydifferent names for intelligent, or advanced,completions, but each suggests a significantimpact on asset management. Data acquisition,interpretation and the ability to optimize pro-duction by remotely adjusting downhole valvesdistinguish advanced completions from traditionalcompletions and offer the ability to interactivelyaddress a situation before it becomes a problem.
The foundation for successful use of surface-operated flow-control equipment downhole isreservoir data that help in decisions about effi-cient production of reserves. In an ordinary com-pletion, reservoir monitoring occurs only at
2. A well intervention might add as much as 30% to the $6 million to $8 million construction cost of a subsea well,whereas the initial intelligent completion might cost lessthan the intervention and provide better results over thelife span of the well. See: Greenberg J: “IntelligentCompletions Migrating to Shallow Water, Lower CostWells,” Offshore 59, no. 2 (February 1999): 63-66.
3. For examples of intelligent completion economics: Jalali Y, Bussear T and Sharma S: “IntelligentCompletion Systems—The Reservoir Rationale,” paper SPE 50587, presented at the 1998 SPE European Petroleum Conference, The Hague, The Netherlands, October 20-22, 1998.
4. Robinson MC and Mathieson D: “Integration of an Intelligent Completion into an Existing Subsea Production System,” paper OTC 8839, presented at the 1998 Offshore Technology Conference, Houston, Texas, USA, May 4-7, 1998.Other sources indicate that that first intelligent completion installation actually occurred in September 1997: See Greenberg, reference 2.von Flatern R: “Smart Wells Get Smarter,” Offshore Engineer (April 1998): 45-46.
Autumn 1999 21
specific times. Well tests, production logs andseismic surveys provide one-time snapshots ofthe reservoir and might not represent the reser-voir’s normal behavior or record events thatrequire corrective action. In complex well config-urations, such as multilateral wells, productionlogging is difficult. Simply getting to the reservoirto acquire data can be risky, time-consuming andexpensive. Subsequent workover operations,such as plugging and abandoning a zone, can bechallenging and costly because a workover rigmust be brought to the wellhead and remediationequipment placed in the wellbore.
Permanent downhole gauges are incorpo-rated in intelligent completions to allow continu-ous data acquisition. Historically, oil companyreservoir engineers came up with the idea tomonitor downhole conditions in onshore USAwells in the 1960s. The first gauge installationswere actually modified wireline equipment.Significant developments in permanent monitor-ing technology have been made since those earlydays. Today, permanent gauges have establishedan impressive worldwide track record for reliablymonitoring downhole pressure, temperature andflow rate.6 Real-time or near real-time pressure,temperature and flow-rate data show the contin-uous variation in reservoir performance. Whilesecond-by-second data collection might seemexcessive during routine production operations,the abundance of data ensures that high-qualityanalysis can be performed when needed.
The wealth of data afforded by permanentgauges means that the reservoir team no longerhas to speculate about what is going on down-hole. By gathering and analyzing reservoir data,the team can decide if or when adjustments tothe completion might be appropriate. Once reser-voir behavior has been carefully evaluated, theteam can use actual data rather than assumedinput values in reservoir simulations and continueoperations or adjust downhole conditions usingremotely controlled valves operated from surface.
Field-proven flow-control valves are hydrauli-cally actuated Variable Window valves that canbe incrementally adjusted to control the flowarea more accurately. In contrast, their less reli-able predecessors, sliding sleeves, are eitherfully opened or completely closed and cannot beadjusted between those two positions. By vary-ing the slot width of the Variable Window valve,flow rates can be adjusted. In essence, the flowrate of each control valve is tailored to theindividual zone.
The flow-control valve is mounted in a side-pocket mandrel, or a cylindrical section offsetfrom the tubing, so that the valve can beretrieved by wireline or slickline if necessary(above left). By applying hydraulic pressure, a
Variable Window valve can assume one of sixsequential positions to set the rate at which flu-ids are produced from the formation into the tub-ing or injected from the tubing into the formation.Reservoir management requires both productionand injection capabilities. Check valves preventcrossflow between reservoirs.
An electrically controlled valve is in devel-opment (above). The electric version allowsinfinite adjustment between the opened andclosed positions rather than the incrementaladjustments of the hydraulic version. Like wire-line-retrievable flow controllers, the electricallyand hydraulically operated, tubing-retrievable flowcontrollers in development have no practical depthlimitations and can include instruments to mea-sure formation temperature, pressure and flow.
Section B-B
AA
Section A-A
B B
Retrievablevalve
Hydraulicactuator
Productiontubing
Control linesto surface andlower zones
> Flow-control valves. The WRFC-H hydraulic wireline-retrievable flow-control valve can beadjusted to six positions, one of which is closed.The middle position is a setting that meets anticipated requirements. From this median setting, there can be two adjustments downwardor upward to control fluid production or injection.
5. For other descriptions of intelligent completions: Beamer A, Bryant I, Denver L, Saeedi J, Verma V, Mead P, Morgan C, Rossi D and Sharma S: “From Pore to Pipeline, Field-Scale Solutions,” Oilfield Review 10, no. 2 (Summer 1998): 2-19.Huck R: “The Future Role of Downhole Process Control,”Invited Speech, Offshore Technology Conference,Houston, Texas, USA, May 3, 1999.
6. Baker A, Gaskell J, Jeffery J, Thomas A, Veneruso T and Unneland T: “Permanent Monitoring—Looking atLifetime Reservoir Dynamics,” Oilfield Review 7, no. 4(Winter 1995): 32-46.Permanent monitoring and the reliability engineeringbehind the current generation of permanent gauges willbe the focus of an upcoming Oilfield Review article.
Permanent gauges
Electricactuator
Choke
> Flow-control valve developments. The TRFC-Eelectric tubing-retrievable flow-control valve can be adjusted to an infinite number of positions,providing greater control than its hydraulic counterpart. This advanced all-electric systemcontains a single cable for power and telemetry.Qualification tests are ongoing.
Reliability of flow-control devices is a criticalconcern because, like permanent gauges, theyare meant to last for the life of the well and, withthe exception of wireline-retrievable devices, arenot usually recovered for repair, maintenance or post-mortem failure analysis.7 These demandsmake long-life field trials impractical and identifi-cation of risks through other techniques essen-tial. Simple, robust and field-proven equipment isfundamental to the designs. Therefore flow-con-trol valves incorporate proven technology, suchas hydraulic motors from subsurface safetyvalves. Newly developed components havepassed rigorous qualification tests.
Initially, it might be difficult to choose frommyriad options for completing a wellbore in anew reservoir. Until the reservoir has been char-acterized to the satisfaction of the operationsteam, completion specialists recommend ensur-ing flexibility, continuously acquiring data andthen using reservoir-modeling tools to comparepredictions with actual results.
Flow Control in ActionIn two well-known fields, reserves that mighthave been left in the ground are being recoveredthrough the use of flow-control devices. Forexample, a thin oil zone in the massive Troll fieldis being drained by extended-reach or horizontalwells that contact a greater area of the reservoirthan vertical wells and reduce the drawdown perunit area to avoid premature gas coning. Aninnovative multilateral well in the Wytch Farmfield enables production from two different sec-tions of an oil reservoir.
Troll field, operated by Norsk Hydro andStatoil, contains the world’s largest offshore gasreserves. There is a thin oil zone below the enor-mous gas cap. When the field was discovered inthe 1970s, and as recently as 1985, technologyhad not yet been developed to recover the oilreserves. Advances in horizontal drilling nowmake it possible to drill 3000- to 4000-m [9840- to 13,120-ft] sections horizontally throughthe relatively uniform, unfaulted sandstone
22 Oilfield Review
HELIKOPTER SER V
ICE
NORTH SEA
NORWAY
UK
Troll field. The Troll C platform willinitially produce oil from the Troll OilGas Province. All Troll field wells aresubsea completions, five of whichhave flow-control devices.
7. Veneruso AF, Sharma S, Vachon G, Hiron S, Bussear Tand Jennings S: “Reliability in ICS* IntelligentCompletions Systems: A Systematic Approach fromDesign to Deployment,” paper OTC 8841, presented atthe 1998 Offshore Technology Conference, Houston,Texas, USA, May 4-7, 1998.
reservoir to drain the oil. Troll C platform, whichwill begin production during the fourth quarter of1999, will initially produce oil from a highly per-meable sandstone reservoir at a depth of 1580 m[5184 ft] in the Troll Oil Gas Province (below).
The key technical issue for the 40 wellsplanned from the Troll C platform is to recover oilfrom the 2- to 18-m [6.5- to 59-ft] thick oil legwithout gas coning. The completions, which aresubsea, produce oil in the presence of nearbywater more readily than in the presence ofnearby gas. Use of advanced completion technol-ogy was considered at the outset, before drillingthe first well from the platform.
Troll field
>
Autumn 1999 23
A traditional approach in this region wouldhave been a directionally drilled well with a slot-ted-screen completion (above). The risk in thiscase is gas or water coning. The preferredapproach was to directionally drill the well intothe lower part of the oil zone and install a wire-line-retrievable flow-control valve to help withgas lift (right). The well now produces oil andwater, but eventually will produce gas. Untilthen, alternating cycles of production with orwithout gas lift through the flow-control valveallow oil production without gas coning.
The combination of horizontal drilling tech-nology to drill low in the oil pay, downhole gas-lift technology rather than injection from surfaceto accelerate production, and downhole flow-control valves enhanced project economics. Theelimination of gas-gathering and high-pressuredistribution systems helped reduce costs, in partbecause a smaller, less expensive platform with-out compression facilities could be used. In theabsence of flow-control technology, significantamounts of oil in the Troll field might have beenleft behind, but advanced completions willimprove ultimate recovery by an estimated 60million barrels of oil [9.5 million m3]. At present,five wells in the field have intelligent comple-tions, with four or five more planned for 2000 andseven installations in 2001.
Gas coningTraditional completionWater coning
Gas
Oil
Water
Gas coning. Standard completiontechnology (center) would haveresulted in limited total oil recovery dueto premature gas coning (right). Oil isnow produced along with water (left).
Gas-lift cycle
No gas lift during this cycle
Perforations
Gas
Oil
Water
Preferred solution. By carefullysteering the well into the lowerpart of the thin oil leg, oil reservescould be produced along withwater (top). Periodic gas-liftcycles provide artificial lift (bottom left).
>
>
Poole
Poole Harbor
Bournemouth
IRELAND UK
PooleLondon
Sherwood sandstone reservoir
Well M-2 TD location
Poole Harbor
Poole
Surface wellsite M
Purbec
Bournemouth
In another example of the use of intelligentcompletions, record-setting extended-reachwells drain portions of the Triassic Sherwoodsandstone reservoir beneath Poole Bay in theWytch Farm field, operated by BP Amoco inDorset, England (above).8 Because these wellsare without precedent, the BP Amoco operatingteam has developed and benefited from a will-ingness to consider new technologies, resultingin pioneering approaches to well constructionand completion design.9
The Wytch Farm M-2 well was drilled in 1994.During cementing operations, the cement slurryflash set inside the casing and could not bepumped up the annulus to isolate the sandstonereservoir effectively. The 51⁄2-in. liner could not beremoved, so the team elected to perforate theliner and produce the well. When the water cutrose sharply, the team explored other options forthe well. A key economic driver was the internalceiling on lifting costs. Therefore, during its anal-ysis, the team considered the impact of the com-pletion throughout the life span of the well ratherthan focusing on the initial cost of the completion.
Around this time, the flow-control devicedeveloped by Camco was successfully installedin the Troll field. The Wytch Farm team was moti-vated to consider applying new technology, suchas an adaptation of the flow-control device usedin the Troll field. The economics for an advancedcompletion with flow-control valves were favor-able, so the team explored ways to incorporatethe new technology in the M-2 wellbore.
Eventually, the group decided to plug the M-2wellbore and convert the well—renamed the M-15—to a multilateral well with two side-tracks.10 A multilateral well with an advancedcompletion functions much like two wells, butwithout doubling the construction expenses (nextpage, top). The primary Sherwood sandstonereservoir would be tapped by a simple openholecompletion. Another lateral would penetrate afaulted portion of the Sherwood reservoir thathad high potential for water production. An elec-tric submersible pump would provide artificial lift(next page, bottom).11
24 Oilfield Review
>Wytch Farm field. Significant oil reserves lie beneath Poole Bay and are drained byextended-reach wells. The M-2 well, shownin black, was renamed M-15 and converted toa multilateral well that contains hydraulicallyactuated flow-control valves.
8. For more on extended-reach drilling at Wytch Farm field:Allen F, Tooms P, Conran G, Lesso B and Van de Slijke P:“Extended-Reach Drilling: Breaking the 10-km Barrier,”Oilfield Review 9, no. 4 (Winter 1997): 32-47.McKie T, Aggett J and Hogg AJC: “Reservoir Architectureof the Upper Sherwood Sandstone, Wytch Farm Field,Southern England.” in Underhill JR (ed): Development,Evolution and Petroleum Geology of the Wessex Basin,Special Publication 133. London, England: GeologicalSociety, 1998: 399-406.Smith GS and Hogg AJC: “Integrating Static andDynamic Data to Enhance Extended Reach WellDesign,” paper SPE 38878, presented at the SPE AnnualTechnical Conference and Exhibition, San Antonio,Texas, USA, October 5-8, 1997.
9. Gai H, Davies J, Newberry P, Vince S, Miller R and Al-Mashgari A: “World’s First Down Hole Flow ControlCompletion of an ERD Multilateral Well at Wytch Farm,”abstract submitted to the IADC/SPE Drilling Conference,New Orleans, Louisiana, USA, February 23-25, 2000.
10. For more on multilateral wells: Bosworth S, El-Sayed HS,Ismail G, Ohmer H, Stracke M, West C and Retnanto A:“Key Issues in Multilateral Technology,” Oilfield Review10, no. 4 (Winter 1998): 14-28.
11. For more on artificial lift: Fleshman R, Harryson andLekic O: “Artificial Lift for High-Volume Production,”Oilfield Review 11, no. 1 (Spring 1999): 48-63.
Autumn 1999 25
Flowmeter
Electricsubmersiblepump shroud Formation
savervalve
Multisensor Original M-2 wellbore plugged and cemented
Electricsubmersible
pump packers
Electricsubmersible
pump
Hydraulicdisconnect 8 1/2-in. lateral
Packer 7-in. linerSumppacker
4 1/2-in.WRFC-H
> Flow-control solution. A multilateral well with three WRFC-H flow-control valves proved to be economically and technically viable because it allowed separate control of each lateral as well as independent testing of each wellbore. The M-15 well is the first in which remotely operated flow-control valveshave been installed below an electric submersible pump.
Oil
Water
Oil
Water
ORAUT99-Completion-Fig.13.2
Oil
Oil
Water
Water
> Noncommercial solutions. Drilling two wells would have been prohibitively expensive (left). A single well would have left behind reserves (right).
The M-15 well design addressed three key areas of concern:• Flow control• Pressure drawdown• Well testing.
Flow control to deal with expected water pro-duction from one lateral—The team anticipatedthat flow control would allow recovery of anadditional 1 million barrels [158,900 m3] of oilthat might not have been recovered otherwise.
Drawdown control to avoid hole collapse inthe openhole completion—The sandstone reser-voir drained by the primary lateral was expectedto be relatively unfaulted and competent. Casingthis lateral would have been uneconomic. Themudstone caprock was penetrated nearly hori-zontally, so there was potential for collapsing themudstone if drawdown were higher than a cer-tain specified level. Hole collapse could alsodamage the electric submersible pump.
Well testing and data acquisition concerns—BP Amoco wanted to better understand the pro-duction profiles of extended-reach wells bycapitalizing on the monitoring equipmentplanned for the M-15. In addition, a completionwith downhole flow control would allow the twobranches to be tested independently. The abilityto observe the dynamics of the reservoir usingdownhole equipment, rather than having to inter-pret ambiguous measurements made at the sur-face, was a key concern for the team.
After evaluating flow-control devices avail-able at the time, the completion team chose todeploy three WRFC-H hydraulic wireline-retriev-able flow-control devices, two in the primary lat-eral and one in the second lateral. This equipmentwould allow the water leg predicted in the faultedreservoir to be shut off while producing from theother lateral (above). In addition to flow-
control devices, the M-15 equipment includes athird-party flowmeter above and a sensor imme-diately below the electric submersible pump. Theflowmeter measures total flow through the pump,pump discharge pressure and pressure upstreamof the flow-control valve that controls the south-ern lateral. The multisensor, mounted at the bot-tom of the electric submersible pump, measuresfluid and motor-winding temperatures, vibrationand intake pressure in the barefoot lateral anduses the pump cable for signal transmission. Themultisensor and flowmeter were positioned tohelp the team understand the performance ofeach lateral, but early failure of the upperflowmeter impeded investigation of the interac-tion of the two wellbores. Fortunately, the teamwas able to establish the integrity of the installa-tion and the drawdown level before gauge failure.
Installation proceeded according to plan. The flow-control equipment continues to allowthe two laterals to be controlled individually fromthe surface.
26 Oilfield Review
Oil
Water
Oil
Water
Oil
Water
Oil
Water
> Shutting off water. Both laterals are producing oil (left). If the lower lateral waters out, the flow-control valve can be closed to prevent water production (right).
Autumn 1999 27
Like other extended-reach wells in the WytchFarm field, the M-15 well set several records. TheM-15 has the greatest reach of any dedicatedmultilateral well. It set additional records with3400 m [11,155 ft] of horizontal 81⁄2-in. hole in one lateral, 2600 m [8530 m] of 7-in. liner floatedinto position, whipstock retrieval at 5300 m[17,390 ft] and 85 degrees, and 1800 m [5905 ft]of perforating guns run to 8000 m [26,248 ft]—arecord since broken by the M-16 well. It is alsothe first well worldwide in which a surface-con-trolled flow device has been installed below anelectric submersible pump.
The M-15 example confirms that flow-controldevices work as designed, so future decisionsabout using them will be based on project eco-nomics and long-term performance reliability.Installing advanced completion equipmentrequires a properly trained wellsite crew. Carefulpreparation is a key to success. A completionsimilar to the Wytch Farm M-15 example wouldbe appropriate in other areas to control draw-down or water production from layered reservoirsand reservoirs with high contrasts in pressure,permeability and water cut.
Currently, advanced completions are used inareas where interventions are most costly—deep-water, arctic and environmentally sensitive loca-tions—which also tend to have more complicatedwells. To date, five valves have been installed inthe Troll field and three valves in the Wytch Farmcompletion, all of which continue to function.
Other applications of flow-control valves andpermanent gauges are available. For example, ina field that has gravity-drainage oil production,downhole gas production and autoinjection mayeliminate the need for gas-production and gas-injection wells, in addition to replacing costly sur-face facilities (right). Such downhole repressuringin the wellbore is not only cost-effective, but envi-ronmentally more benign.
Another application is for commingling pro-duction in stacked reservoirs with potential forcrossflow or in areas where government regula-tions require separate accounting for productionfrom separate hydrocarbon zones.12 In fieldsundergoing secondary recovery, such as water-floods, flow-control devices and permanentgauges can help maintain critical injection rates.
This will help avoid premature breakthroughcaused by injecting fluid too rapidly and preventinefficient displacement of reservoir fluids due to an injection rate that is too low.13 Clearly,remote monitoring and control of flow canaddress complications presented by multiplereservoirs, multiple fluid phases, formations thatare sensitive to drawdown pressures and com-plex well configurations.
Producer Autoinjector
Injector
> Producing gas-free oil. Gas separation typically requires surface facilities to remove gas from oil-and gas-injection wells. The left wellbore produces gas. The middle wellbore is a gas-injection well.Downhole gas production and autoinjection using flow-control technology, shown at the right, canreplace costly surface facilities and gas-injection wells.
12. See Jalali et al, reference 3.13. See Jalali et al, reference 3.
Future Remote Monitoring and Flow Control Monitoring and controlling flow from the surfaceare the first stages in optimizing reservoir plumb-ing. Ideally, future reservoir management willroutinely involve observation and data gathering,interpretation and intervention (below). Dynamicupdating of the reservoir model using feedbackfrom real-time monitoring maximizes the value of the data and allows the operator to makeinformed adjustments to downhole valves thatcontrol flow from the reservoir by determiningthe optimal flow.
To assess the impact of real-time data collec-tion and flow control on recovery, a laboratoryexperiment was designed by the ReservoirDynamics and Control group at Schlumberger-Doll Research, Ridgefield, Connecticut, USA. Theexperimental apparatus simulates a deviatedwell in an oil reservoir near an oil-water contact(right). The Berea sandstone reservoir in the
28 Oilfield Review
> Experimental apparatus. The laboratory setup (right) represents a deviated well with three valvesthat control flow from the producing zones (left). The reservoir is initially saturated with fresh water,which is displaced by injecting salt water from below, simulating an underlying aquifer.
14. The Berea 500 sandstone, a quartz-rich, LowerCarboniferous sandstone from Ohio that is prized for itsdurability, is widely used in petroleum industry tests.For more on the Berea sandstone:http://www.amst.com/red_sandstone_products.html.
Reservoir monitoringand control - Sensor type and location - Flow-control equipment and location
Shared earthmodel
Project goals andconstraints - Maximize recovery - Maximize net present value - Flow rate - Pressure - Water cut
Dynamic Updating
Simulation andoptimizationalgorithm
> Designing an optimization strategy through monitoring, simulation and control. Dynamic updating isthe critical ingredient in reservoir monitoring and control. Depending on the field and the operator, production goals differ. In one field, maximizing flow rate might be the objective. In other cases, maximizing ultimate recovery or net present value might be more important. Once the objectives are defined, flow-control equipment and sensors can be properly placed in the well. As more databecome available, the shared earth model is updated. Reservoir simulation and an optimization algorithm incorporate economic and practical constraints into the shared earth model. Simulation and optimization output values of control variables, such as flow rate and pressure, allow the operatorto adjust completion devices appropriately.
experiment was saturated with fresh water torepresent oil in an actual reservoir.14 The “oil”was displaced by salt water that represents con-nate water in an actual reservoir.
The “well” has three flow-control valves.When the valves were opened fully, “oil” pro-duction was followed by early “water” break-through at the deepest completion in thewellbore because this part of the well is closestto the “oil-water” contact and is the path of leastresistance. Consequently, the reservoir waspoorly swept.
An optimal production strategy was thendesigned using the model that had been preparedfor the laboratory reservoir. A simulation, per-formed with ECLIPSE reservoir simulation soft-ware, was linked to an optimization algorithm thatincorporated an objective of maximum recoveryand practical constraints, such as the reservoirpressure at each part of the wellbore, fixed totalproduction rate and maximum water cut. The sim-ulation showed that more oil could be recoveredby varying the offtake in the different segments ofthe well. By adjusting the valves in the next phaseof the experiment, more “oil” was indeed recov-ered because the “water” front approached thewellbore evenly rather than breaking through onezone of the completion prematurely.
Autumn 1999 29
In the experiment, adjustment of flow intoeach of the valves was made on the basis ofobservations of the front movement usingcomputer-assisted tomographic scans (left). Insubsurface reservoirs it will also be necessary toimage the front movement in order to devise acontrol strategy, and research is under way todevelop reliable sensors for this purpose.
The experiment clearly demonstrated thatproducing each zone at its optimal rate improveshydrocarbon recovery from the well (below left).When the valves in the wellbore were fullyopened, only 75% of the “oil” was displaced. Byjudiciously adjusting the three valves in theexperimental apparatus, sweep efficiencyincreased to 92%.
State-of-the-art monitoring and flow-controltechnology minimize the need for well interven-tions and make those that are necessary morecost-effective by simplifying them or timing themoptimally. As demonstrated in the Wytch Farmand Troll field examples, additional incrementalreserve recovery is more likely when individualzones or wellbores can be operated indepen-dently, produced at precise rates to avoid wateror gas coning or excessive drawdown, andassisted by artificial-lift systems.
Intelligent completions also affect the waypeople work. Design of these systems involvescloser interactions on a technical basis betweenoperators and service and equipment providers toensure safer and more effective completions. Aremotely operated intelligent completion mayreduce the number of people needed at the well-site, so field operations become less expensiveand more people can remain in their offices.
Application of this technology is in itsinfancy—there are now fewer than 20 advancedcompletions worldwide. Advanced completiontechnology is currently most useful in high-costareas, but ultimately will enter lower tier costmarkets as the technology is simplified andproven in other operating theaters. A future chal-lenge will be to build intelligent completionsequipment for casing less than 7-in. in diameter.The combination of the expertise of Camco in flow-control valves and the track record ofSchlumberger in downhole electronics offers aunique ability to both monitor and control flow.The joint efforts of reservoir specialists and com-pletion experts will put downhole process controlon the road to ubiquity. —GMG
No control
Oil
Water
Control
> Impact of flow control. Tomographic images from the experiment convey the impact of flow control.The top photographs, taken during the initial phase of the experiment with the valves open throughout,show the water contact migrating unevenly toward the wellbore. The photograph at the far right shows premature water breakthrough at the lowest valve. The bottom photographs show greater sweep efficiency because the valves are adjusted during production. The “water” contact approaches the wellbore evenly.
180 cm3/hrInjection
180 cm3/hr
180 cm3/hr cm3/hr27 49.5 103.5
No controlFlow rate
Control
75% 92%
> Results of the optimization strategy. Without any control of flow, premature waterbreakthrough at the lowest valve and poor sweep led to displacement of 75% of the “oil” (left). Careful adjustments of the three valves allowed the same flow rate, but better sweep efficiency and recovery of 92% of the “oil” (right). In both illustrations, the white curve represents the “oil-water” contact. In this experiment, the objective was to maximize sweep efficiency while maintaining constant total flow and water cut less than 30%.
