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18 Oilfield Review

Intelligent Completions at the Ready

The merits of intelligent completions are well documented, but their perceived high

initial costs for design, installation and maintenance keep them out of many

operators’ development plans. A new offering is likely to change that perception;

these smaller, modular systems lower costs while retaining all the advantages of the

larger and more-complex, high-tier systems.

Kevin BeveridgeClamart, France

Joseph A. EckRosharon, Texas, USA

Gordon Goh Kuala Lumpur, Malaysia

Ronaldo G. IzettiPetrobrasRio de Janeiro, Brazil

Maharon B. JadidWillem Ruys SablerollePETRONASKuala Lumpur, Malaysia

Gabriela ScampariniRavenna, Italy

Oilfield Review Autumn 2011: 23, no. 3. Copyright © 2011 Schlumberger.For help in preparation of this article, thanks to Claire Bullen and David Nuñez, Houston; and Farid Hamida, Rosharon, Texas.IntelliZone Compact, UniConn and WellBuilder are marks of Schlumberger.

Intelligent well systems were originally con-ceived in response to the extreme costs associ-ated with certain well intervention operations in critical or remote areas, particularly in deep and ultradeep waters. The costs of workovers, recom-pletions and even some forms of basic mainte-nance on wells in water depths greater than about 150 m [500 ft] are often prohibitively high because these operations can be performed only from floating platforms.

Because such vessels are expensive to lease and to move, and subsea workovers are typically long term, operators are reluctant to contract a deepwater rig for a single workover or recomple-tion that does not promise significant return on investment. In addition, because these are often high-rate wells, the cost of lost production during shut-in may be a critical consideration when an operator is contemplating the merits of an inter-vention. Taken together, these factors often cause

1. For more on intelligent completions: Algeroy J, Morris AJ, Stracke M, Auzerais F, Bryant I, Raghuraman B, Rathnasingham R, Davies J, Gai H, Johannessen O, Malde O, Toekje J and Newberry P: “Controlling Reservoirs from Afar,” Oilfield Review 11, no. 3 (Autumn 1999): 18–29.

Dyer S, El-Khazindar Y, Reyes A, Huber M, Raw I and Reed D: “Intelligent Completions—A Hands-Off Management Style,” Oilfield Review 19, no. 4 (Winter 2007/2008): 4–17.

2. Aggrey GH, Davies DR and Skarsholt LT: “A Novel Approach of Detecting Water Influx Time in Multizone and Multilateral Completions Using Real-Time Downhole Pressure Data,” paper SPE 105374, presented at the SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, March 11–14, 2007.

Aggrey G and Davies D: “Real-Time Water Detection and Flow Rate Tracking in Vertical and Deviated Intelligent Wells with Pressure Sensors,” paper SPE 113889, presented at the SPE Europec/EAGE Annual Conference and Exhibition, Rome, June 9–12, 2008.

3. Sakowski SA, Anderson A and Furui K: “Impact of Intelligent Well Systems on Total Economics of Field Developments,” paper SPE 94672, presented at the SPE Hydrocarbon Economics and Evaluation Symposium, Dallas, April 3–5, 2005.

> Detecting water encroachment using downhole sensors. Because water influx at a zone causes a reduced production rate at that zone, the rates will increase in the other zones to ensure the well meets total well constraints, such as liquid rates or tubinghead pressure set by the operator. This change is manifested in a corresponding decrease or increase in pressure drop between zones. In this production scenario, at about Day 700, water breakthrough at the toe (blue) of a two-zone horizontal well creates a sharp decrease in pressure drop (red) between that zone and the sensor at the heel of the well. As water production increases from the heel of the well, around Day 1,160 (green), the pressure drop decreases more slowly. At about day 1,700, with increasing water production from the heel, the pressure drop increases. (Adapted from Aggrey et al, 2008, reference 2.)

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Pressure dropWater cut in toe zoneWater cut in heel zone

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Autumn 2011 19Autumn 2011 19

operators to postpone needed interventions. Such delays can lower production rates over an extended period of time, cause permanent damage to reser-voir productivity and reduce ultimate recovery, all of which impact total field economics.

An intelligent completion (IC) can offer an alternative to interventions. ICs include down-hole sensors that allow operators to gather flow and reservoir data remotely. They are equipped with remotely actuated downhole flow control valves (FCVs) with which operators can adjust flow from individual production zones.1

Remote sensors eliminate the need for the most common intervention in multizone wells: to identify the location of production-inhibiting problems such as water, gas or sand ingress. Sensors that measure changes in flow rate, tem-perature and pressure at specific well depths allow engineers to determine in real time which zone is experiencing production or pressure decline, without the expense and risk of an inter-vention (previous page).

Once engineers identify the source of a prob-lem, they can then shut off, increase or decrease flow from any zone using FCVs placed across each production interval and reconfigure the completion.2 This may be especially cost-effec-tive when initial changes to FCV settings must be further adjusted based on measurements taken during a flow period following the initial remedial operation.

When ICs were first introduced, companies resisted installing them. Engineers questioned, with some justification, the reliability of the systems’ critical components over the life of the well. Operators were equally wary of the capital expenditure (capex) of ICs, which has tradition-ally been substantially higher than that of con-ventional completions. As a result, economics and risk analyses often favored standard com-pletions over ICs except in remote areas or for subsea completions.

Improvements in components and systems and years of IC use have done much to overcome

industry misgivings about the reliability of ICs. However, because their design and implementa-tion are complex, ICs remain relatively expen-sive. Consequently, their use continues to be restricted mainly to remote environments and in wells with very high production rates for which the cost of intervention and delayed production is extreme.

More recently, their appeal has widened as engineers have learned to use ICs as effective reservoir management tools. Multizone comple-tions, waterfloods, gas lift and other systems are more easily optimized through remote downhole monitoring and control than through interven-tion. In many cases, the return on investment in ICs—through accelerated cash flow and increased ultimate recovery—far exceeds the savings realized by avoiding interventions. One major operator has calculated that 5% of the total economic impact of ICs on its business is due to savings on interventions, while 60% is due to reservoir-related revenue increases.3

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20 Oilfield Review

Engineers have also discovered that ICs can be instrumental in reducing the number of wells required to exploit a formation. Reducing well count, intervention frequency and intervention-associated delayed production can save opera-tors millions of dollars in field development costs, particularly in deep water.4 Fewer wells also result in less subsea equipment and thus sub-stantial reduction in capex. Additionally, water and gas processing units that service ICs may be smaller because excess water and gas production may be shut off or reduced downhole rather than treated on the surface. Zonal isolation and pres-sure optimization between zones result in higher rates of commingled flow to the wellbore. The consequence is a net increase in production and total recovery.

With surface-controlled FCVs, it is also possi-ble to periodically measure reservoir and flowing bottomhole pressure (FBHP) without running

production logs. This is accomplished by first closing one zone, which allows the downhole pressure sensor at the sandface to begin record-ing annular, or reservoir, pressure. At the same time, a sensor across a fully opened second zone measures the FBHP for that zone.

When the second zone is closed and the first zone is opened, sensors at the sandface measure the reservoir pressure of the second zone and FBHP from the first zone (above). This tech-nique, which can be applied to a number of pro-ducing intervals at a time, allows operators to gather a downhole pressure profile from any zone at any time without excessive delays in produc-tion for buildup and without exposure to risk from interventions. This technique of isolating zones also enables engineers to collect formation pressure buildup survey information and a draw-down profile for productivity index (PI) updates and changes throughout the life of the well.5

Despite proven reliability and a more broadly defined niche for ICs—and because the original intent of the developers was to use ICs in rela-tively high-rate wells—the economics of middle- and low-tier fields are such that operators continue to use traditional completion strategies rather than risk the capex of an IC. ICs were also intended to be robust enough to forestall inter-vention throughout the life of the well—usually more than 20 years—since a single intervention in deep water or other remote area could easily foil any anticipated economic advantage of an IC.

This design mandate resulted in ICs that were necessarily large, complex and costly. Additionally, over time, as industry providers sought to increase IC reliability and flexibility, the technology evolved piecemeal. Operators seeking best-of-class solutions often had to com-bine components from numerous suppliers within a single completion configuration. This created interface challenges that led to increased risk of equipment failure and wellsite time and costs to assemble, test and install completions.

All these factors have conspired to perpetu-ate the image of wells equipped with remote monitoring and control as large capital expendi-tures justified only by high-volume production, well complexity or locations where intervention is cost prohibitive or technologically problem-atic. This article describes redirected efforts that have given rise to a less complex IC system. Its design lowers its cost, which allows operators of average to marginal wells to reap the reser-voir management benefits of ICs previously restricted almost exclusively to high-cost or high-risk applications.

4. Sakowski et al, reference 3.5. Chen JHC, Azrul NM, Farris BM, NurHazrina KZ,

Aminuddin MKM, Saiful Anuar MY, Goh GKF, Kaur PKS, Darren Luke TK and Eddep A: “Implementation of Next Generation Intelligent Downhole Production Control in Multiple-Dipping Sandstone Reservoirs, Offshore East Malaysia,” paper SPE 145854, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, September 20–22, 2011.

6. Sharma AK, Chorn LG, Han J and Rajagopalan S: “Quantifying Value Creation from Intelligent Completion Technology Implementation,” paper SPE 78277, presented at the SPE European Petroleum Conference, Aberdeen, October 29–31, 2002.

7. Narahara GM, Spokes JJ, Brennan DD, Maxwell G and Bast M: “Incorporating Uncertainties in Well-Count Optimization with Experimental Design for the Deepwater Agbami Field,” paper SPE 91012, presented at the SPE Annual Technical Conference and Exhibition, Houston, September 26–29, 2004.

8. Adeyemo AM, Aigbe C, Chukwumaeze I, Meinert D and Shryock S: “Intelligent Well Completions in Agbami: A Review of the Value Added and Execution Performance,” paper OTC 20191, presented at the Offshore Technology Conference, Houston, May 4–7, 2009.

> Reservoir and flowing bottomhole pressures from remote monitoring and control. In a multizone IC, each zone is isolated, monitored and controlled. The flowing bottomhole pressure (FBHP) may be measured as flow from Zone 2 only (red arrows) by closing the FCV across Zone 1 (top), while reservoir buildup pressures in the shut-in Zone 1 are measured. By closing the FCV across Zone 2 and opening Zone 1 (bottom), reservoir pressure may be determined in Zone 2 and FBHP from Zone 1. The principle may be applied to any number of isolated zones.

Zone 1 Shale ShaleZone 2

Annulus sensorreads the Zone 1

reservoir pressure.

Tubing sensorreads the

Zone 2 FBHP.

FCV 1 closes

Shale

Zone 1 Shale ShaleZone 2

Tubing sensorreads the

Zone 1 FBHP.

Annulus sensorreads the Zone 2

reservoir pressure.

FCV 2 closes

Shale

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Autumn 2011 21

The Value of FlexibilityWhen operators plan wells in deep water or other isolated locations, it may be clear that avoiding a single intervention saves enough in operating expense to justify the capital expense of a tradi-tional IC. On the other hand, a single-zone, land-based well in an area well populated with rigs is unlikely to ever justify the expense of an IC even if the operator avoids numerous interventions.

During consideration of scenarios between those two extremes—for example multizone land-based completions—the cost analysis may not be so apparent. Shutting off production from one zone and opening another through recomple-tion or by shifting a sliding sleeve are relatively low-cost propositions built into the original eco-nomics of multizone wells. However, such a strat-egy calls for the first zone to be depleted before the next one is opened. Reservoir analysis indi-cates that remotely adjusting downhole FCVs to commingle zones based on real-time pressure and temperature data significantly accelerates production and increases ultimate recovery com-pared with traditional on-off multizone comple-tion configurations (above right).

This advantage is not always apparent because traditional discounted cash flow mod-els used by most operators cannot quantify the value derived from operational flexibility.6 This flexibility depends on the availability of numer-ous options with which to mitigate well prob-lems during the life of a well. Having the ability to remotely monitor downhole conditions and adjust flow from various zones in real time adds to the number of choices available to the operator, removing the economic burden of rig-based interventions.

Remote monitoring and control is a particu-larly powerful tool for reducing uncertainty in reservoir properties. For example, as with many deepwater developments, the operators of the Agbami field offshore Nigeria did not have substantial reservoir data on which to base well plans.7

Agbami wells are typically completed in mul-tiple zones within the same faulted reservoir. Pressure equilibrium indicated the zones are in communication, although uncertainties persisted in vertical and lateral crossfault connectivity under dynamic conditions (right). Consequently, engineers believed that waterflood and gasflood fronts would advance through the reservoir at different rates.

To manage this uncertainty, the operator installed ICs that included permanent pressure, flowmeter and densitometer sensors arrayed from the sandface to the separator. These are monitored through an integrated database and

analysis computer that collects and evaluates sensor output. Variable chokes were placed downhole and at the surface to facilitate remote flow control.8

> Comparing commingled and sequential production. The production benefits of commingling versus an estimated sequential production strategy are demonstrated in a Gulf of Mexico operator’s production curves. Two FCVs were installed in this well to control upper and lower producing zones. The operator used on-off controls to shut off production from one zone when its water cut threatened net production; the result (red) was about a 28% increase over sequential production estimates (blue).

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> Uncertainty about reservoir properties. The pay intervals at Agbami field consist of two principal zones. Uncertainty about permeability, fault seals and injection conformance made decisions about well count and location problematic. The upper, middle and lower 17 MY sands hold about 80% of the reserves. Secondary reservoirs include the 13 MY (not shown), 14 MY and 16 MY layers. [Adapted from Houston Geological Society: “HGS International Dinner June 21, 2004; Agbami Discovery, Nigeria,” (May 25, 2004), http://www.hgs.org/en/art/209 (accessed August 3, 2011).]

14 MY

U 16 MY Secondary reservoirs

Reservoir Model of Agbami Field

Main reservoir

U 17 MY

L 16 MY

M 17 MY

L 17 MY

U = upperM = middleL = lower

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22 Oilfield Review

The operator identified four categories that characterized the value added by using ICs:•incrementalrecoverythroughoptimizedzonal

contributions•reservoir management through effective void-

age replacement and pressure maintenancewith gas and water injection

•optimizedinfilldrillingthroughbettermodelsbased on history-matching of zonal volumesratherthantotalreservoirvolumes

•operatingexpensesavingsthroughreductionorelimination of workovers, sidetracks and pro-duction logging runs to evaluate injection and productioncontributionfromindividualzones.

Usingdynamicsimulationmodels,theopera-tor concluded that the deployment of ICs on a field-wide basis at Agbami would deliver incrementaloil recoveryof84 to138millionbbl[13to22millionm3].9

TheAgbamifieldcontains20producingwells,12waterinjectionwellsand6gasinjectionwellsinabout5,000ft[1,500m]ofwater.Productionin2009was140,000bbl/d[22,250m3/d]ofoilwithpeak production expected to be 250,000 bbl/d[39,730m3/d].Givenitssize,locationandreser-voiruncertainty,Agbamifieldwasanidealcandi-date for ICs.But the success there, in termsofincrementalproductionasaresultofICinstalla-tion,alsodemonstratesthepotentialadvantagesthestrategyholdsforsmallerfieldsiftheinitialcapexcanberecovered.

Smaller, ModularIncontrasttomostIC-candidatewells—thosecharacterized by multiple high-rate targets—manyaveragetomarginalwellsareprofitableonlywhenoperatorsareabletoaccessnumer-ousmarginalproductionzonesatthecostofasinglewellbore.Despitethecomplexityinher-ent in drilling and completing many of thesewells, project economics often demand thatcapexbestrictlylimited.Thisforcesoperatorsto exchange the reservoir management capa-bilities of an intelligent completion for thelower initial costs of traditional mulitzonecompletionconfigurations.

Schlumbergerengineershaverecentlydevel-oped a technical solution to this market-drivenissue by repackaging traditional, high-tier ICtechnology into a significantly lower-cost sys-tem. The IntelliZone Compact modular zonalmanagementsystemwasdeveloped fordeploy-ment in multizone wells that require fewerchokepositionsandareoflowerworkingpres-sures than those of traditional IC-candidate wells.Itissuitedforuseinbrownfieldsormar-ginal fields, in wells that would otherwise useslidingsleevecompletions—mostwithoutmon-itoringsystems—andwells requiringextendedwell testing. The IntelliZone Compact systemimproves recovery in long, horizontal wells bycompartmentalizingthemandcontrolszonesinartificialliftwellsbymonitoringandcontrollinginflowatthesandface.

The IntelliZone Compact system is an inte-gratedassemblyratherthanaconglomerationoftheindividualtoolsthatmakeuptraditionalICs.The downhole flow control assembly includes apacker,ahandlingsubandanFCV(left).FCVsmaybeeitheron-offtwo-positionorfour-positionchokes.Eachassemblycanbetestedatthefac-toryandrunwithaproductionpackeroranisola-tionpackerwithoutslips.

Usingfrequencyshiftkeying(FSK)communi-cationtechnologytotransmitdatatothesurface,thesystemmonitorsdownholepressure,temper-atureandvalvepositioneverysecond.10 The data aretransmittedtothesurfacecontrolsystemviaasinglemonoconductorcable.Ahydraulicpowerunit(HPU)controlsallhydraulic linefluidout-flow, inflow and pressures required to actuatedownholetools.AUniConnuniversalsitecontrol-ler functions as a data-gathering and control plat-form that operates motor control systems,downhole tool systems, SCADA and other com-municationsystems.

The control system fulfills several key func-tions including acquisition and storage of tooldata—annuluspressure, tubularpressure, annu-lus temperature, tubular temperature and FCVposition.Italsoperformstheautomatedsequenc-ingofvalveoperations,alarmdetectionandcondi-tions,tolerancelevels,acquisitionandstorageofHPUdataandremoteSCADAcapability.

ThesystemreliesonWellBuildersoftwareforcompletion design to integrate the completionplanningprocessfromconcepttocommissioning.The WellBuilder program uses reservoir condi-tions,completionrequirementsandconstructionparameters to generate multiple configurationsoftherequirednumberofcontrollinesandoper-atingpressureenvelopelimitsforeachzone.

IntelliZoneCompacttwo-positionFCVsincludea flow control section and an actuator section.The two-position FCV may be either open orclosed. A single actuation, accomplished bybleeding one control line while increasing pres-sureonanother,changesthevalvepositionfromopentoclosedorviceversa.WhenmorethanoneFCV is placed in the well, line sharing allowsreductionofthenumberoflinestooneplusthenumber of valves in the hole. The four-positionFCV includes a choke and an actuator sectionplusaJ-slotindexer,whichcontrolsthechoke’sposition;itcanbeclosed,33%open,66%openor100%open.

Like the two-position FCV, the choke posi-tion is changed one step per actuation by bleed-ing one line and pressuring up another and can alsobeconfiguredforlinesharingtominimizethe number of hydraulic lines installed. The

> Smaller IC package. The modular design of the IntelliZone Compact system allows engineers to assemble and test the IC package for each zone before it is shipped to the wellsite. All electrical and hydraulic connections are welded into place by the manufacturer. Rig operators need only to connect lines at the handling subs and no longer must thread lines through packers and connect them to FCVs and pressure sensors on site, resulting in reduced installation time, cost and risk. A filter sub enhances system durability by preventing contaminants from reaching FCVs. In multizone wells, multidrop modules require fewer hydraulic lines to handle multiple control valves.

Dual pressuregauge

Handling sub

Mounting sub

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Filter sub

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Handling sub

Packer

Electric line

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Autumn 2011 23

Two-pulsemultidrop module

Two-position FCV

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Eight-pulsemultidrop module

Zone 1Four-position FCVMultidrop module

Zone 2Two-position FCVMultidrop module



Zone 5Four-position FCV









0 1 2 3 4Actuation cycle

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Close Open Close Open Close Open Close Open

Close Close Close Close Open Open Open Open

Close Close Open Open Close Close Open Open

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four-position FCV can also use a multidrop mod-ule that allows manipulation of up to three downhole valves through a single control line. A position sensor is integrated into the hydraulic FCV, which is accomplished by programming each FCV to react to a two-, four- or eight-pulse signal (right). Since the valves move in a single direction, a series of pulses may be used to change them from on to off or through the series of choke settings.

Minimizing the number of hydraulic control lines in a completion reduces installation com-plexity—fewer lines require less handling and splicing. The multidrop module also makes it pos-sible to place FCVs at more production zones than would otherwise be possible because of a limited number of available packer or tubing hanger penetrations.

The multidrop module is externally mounted to the tubing within the IntelliZone Compact sys-tem and is connected to the open and closed ports of the FCV and, in series, to the hydraulic control line deployed to the surface. Downhole instrumentation can also be added to the flow control assembly as a modular package by mount-ing pressure and temperature gauges and other hydraulic devices around the tubing sub.

Savings in Brazil and IndiaThe savings generated by the IntelliZone Compact system approach compared with conventional intelligent completions systems are derived from its modularity and standardization. At about 10 m [30 ft] long, it is half the length of standard ICs. Because the isolation device, sensors and flow control valves are packaged in a single assembly, there are no interface issues common to systems built from components supplied by multiple manufacturers. This significantly enhances total system reliability and, because the entire system is assembled and tested at the point of manufacture rather than in the field, it saves operator rig time.

The IntelliZone Compact system also helps operators save time and possible missteps because the control lines are installed as part of the package. Control line handling on site is limited to making splices above and below the package as it is run into the well. In standard applications, these lines must be threaded through the packers and connected to each con-trol valve individually; this is a time-consuming operation fraught with opportunity to damage lines and components. Because fewer lines require handling, risk associated with splicing operations is also reduced.

> Reducing the number of hydraulic lines. In typical completion configurations, each surface-actuated FCV requires a dedicated hydraulic line. A multidrop module interprets pulses from the surface as commands to shift openings of a specific FCV within a well (top). This allows engineers to operate at least one more FCV than the number of hydraulic lines available. For example, using multidrop modules (bottom) allows three 2-position FCVs to be operated on a single control line (black lines, left) or two 2-position plus three 4-position FCVs on two lines (black and green lines, middle) and up to five 4-position FCVs on three lines (black, green and red lines, right).

9. Adeyemo et al, reference 8.10. FSK communication technology uses a robust frequency

modulation scheme that sends digitally encoded data by changing the frequency of a transmitted signal. A

receiver converts the signal back to the original form. The FSK signal is easily connected to other communications devices such as those used by SCADA systems.

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24 Oilfield Review

It was these time and cost savings that influ-enced a Petrobras decision to use an IntelliZone Compact system in the Carapeba-27 injection well of the Carapeba field in the Campos basin offshore Rio de Janeiro. Engineers sought to optimize pro-duction from this mature field by replacing con-ventionally completed, one-zone wells with IC three-zone wells. They chose to use an IntelliZone Compact IC in an injector well to optimize reser-voir sweep and to perform injectivity tests to allo-cate injection rates in each zone. Both objectives are facilitated by the system’s highly accurate posi-tion sensor. Engineers also needed to monitor and control downhole flow remotely through their SCADA system, which was accomplished through the UniConn site controller.

Assembled and tested at the factory, each component of the three-zone modular comple-tion included an isolation or production packer, a dual pressure and temperature gauge for tubing and annulus reading, a multidrop module, a two-

or four-position FCV and an FCV position sensor. Since Carapeba is a brownfield, its project eco-nomics demanded a low-cost system, which was achieved by installation costs that were less than those estimated for traditional ICs (above).

Engineers with an offshore India operator also turned to an IntelliZone Compact solution as it considered how to complete a three-zone well within the economic restraints of a marginal field. They sought to reduce capex by using already purchased equipment. At the same time, they sought optimum return on their investment through control of each zone independently. Given these two constraints, their completion choices were between sliding sleeves and a sur-face-controlled downhole flow control system.

Sliding sleeves require interventions to shift them, and engineers knew that to bring these wells online they would have to perform coiled tubing–conveyed acid treatments across each zone individually. The alternative—treating all

three zones at once—would have resulted in most of the acid entering one high-permeable zone while leaving the other two untreated. Use of traditional surface-controlled flow control sys-tems to isolate each zone was not possible because operation of control equipment for three zones would require more hydraulic lines than existing penetrations in the company-owned wellhead.

The solution included deploying a multidrop module in an IntelliZone Compact system. Engineers were able to deploy surface-controlled downhole FCVs across all three zones using a sin-gle hydraulic line. The systems were deployed with a cased hole packer and two swellable packers to isolate each zone (next page). Using the multidrop module, engineers could open one zone while the other two were closed, ensuring that acid treat-ments were reaching their targets.

> Saving time. Because it has a modular design and can be assembled and tested before arriving at the wellsite, the IntelliZone Compact assembly is prepared to be run in a well in about half the estimated time required to reach the same stage using a standard IC installation. Much of the time saved is a result of steps required of standard IC installations (outlined in red) that are not required when running an IntelliZone Compact completion.

25

20

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Oper

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n, h

Standard IC IntelliZone Compactcompletion

10

5

0

Perform final inspection.

Terminate fittings in the packer.

Arrange control lines and fitprotectors, plates.

Install dual gauge into mandrel.Perform gauge check and pressure test.

Perform electrical test and check gauge.

Function test FCV.

Connect control line to FCV: flush, connect and pressure test.

Pass the control line and electric linethrough the packer feedthrough ports.

Connect packer assembly to tubing inrotary table.

Pick up packer assembly to the rig floor.

Connect gauge mandrel assembly totubing in rotary table.

Pick up gauge mandrel assembly to the rig floor.

Connect FCV assembly to tubingin rotary table.

Pick up FCV assembly to the rig floor.

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Autumn 2011 25

The elimination of three of the four control lines required by traditional systems and of the need for coiled tubing–based interventions saved the operator three weeks of rig time. As a result, the operator optimized production at 165% of the originally expected rate and saved US$ 1 million within the first two months follow-ing system installation.

Low-Cost, High-Technology SolutionOptimizing production requires investment. However, when faced with an asset of marginal reserves, operators are often left to choose only from basic completion scenarios for fear that any incremental production realized through higher technology will not be enough to pay the cost of such a solution. This is especially true when the challenge to increased production is as technical as that faced by engineers at PETRONAS com-pleting a field offshore East Malaysia.

The PETRONAS-operated S-field contains marginal reserves in unconsolidated heteroge-neous sandstone reservoirs. Reserves are in a stacked 40 m [131 ft] thick oil column. Because of the presence of a large gas cap, engineers feared breakthrough would prematurely end pro-duction and cause significant oil reserves to be bypassed. They also had to consider the possibil-ity of water invasion from a moderately strong and active aquifer.11

To reduce well count while maximizing reser-voir contact, PETRONAS engineers planned development of the field using 14 horizontal wells. Horizontal wells create a lower pressure drop at the sandface than do typical vertical or deviated wells with equivalent productivity. This lower drawdown helps reduce the severity of water coning and gas cresting.12

However, when the horizontal section pene-trates zones of differing flow properties, those with higher permeability will deplete first. This can lead to water or gas entering the wellbore through the depleted sections of the producing zone, causing reserves in less permeable areas of the formation to be bypassed. Once such break-through occurs, rig-based remedial operations

may be futile or may be unable to return oil pro-duction to economic levels.

Because zonal property contrasts were high, PETRONAS had to balance initial influx and maintain the ability to react to inflow problems later in the well’s life. To satisfy these require-ments, IntelliZone Compact completions were considered as an alternative to passive inflow control devices (ICDs) for the other six com-mingled producers.13 Wells in the S-field best suited for the application were analyzed and ranked based on the well production profile and dynamic reservoir fluid properties such as water cut and gas/oil ratio. Different sandface produc-tion sensitivities for incremental oil, water-cut reduction, gas/oil ratio profile and FBHP were also performed.

The two wells chosen for the installation—Well-A1 and Well-A2—showed positive zonal inflow control analysis results compared with that of the base case of conventional stand-alone screens. They were completed with integrated modular completion packages that included zonal isolation packers, two intermediate and on-off position FCVs and permanent real-time pres-sure and temperature sensors.

The assemblies were delivered to the wellsite as a single joint less than 9 m [30 ft] long— one-half to one-third the length required for a comparable conventional IC. The assemblies were also pretested with electronics and hydraulic splices welded at the manufacturing center. Each tested connection was locked to the assembly and another metal strip was affixed to the housing to further protect the assembly and to guard against damage from shock during installation.

In addition to reducing the risk of installation failure, these practices shortened installation time by reducing the number of connections to be made and lines to be spliced on site. In the S-field case, installation rig time savings were up to two-thirds per zone compared with that of con-ventional installation, or the equivalent of about US$ 400,000 per well completed.

Following installation, wellbore nodal analy-sis combined with time-lapse modeling was used to predict production scenarios based on reser-voir deliverability for proposed wellbore trajecto-ries. Because detailed geologic and petrophysical properties for each well were unavailable from a history-matching model, these were calibrated from offset field performance. Production simula-tion results indicated how the IntelliZone Compact ICs would enable zonal production and control in

> Adapting to available equipment. Using multidrop modules at each of three zones, engineers were able to control FCVs through a single hydraulic control line (green line). The operator was thus able to use a wellhead in inventory instead of having to purchase a more expensive one with the requisite higher number of penetrations required in traditional three-zone IC installations.

Packer

Perforations

Perforations

Perforations

Zone 1

Zone 2

Zone 3

Packer

Packer

Multidropmodule

Hydraulicline

FCV

FCV

FCV

Multidropmodule

Multidropmodule

11. Chen et al, reference 5.12. For more on extended-reach drilling: Bennetzen B,

Fuller J, Isevcan E, Krepp T, Meehan R, Mohammed N, Poupeau J-F and Sonowal K: “Extended-Reach Wells,” Oilfield Review 22, no. 3 (Autumn 2010): 4–15.

13. For more on inflow control devices: Ellis T, Erkal A, Goh G, Jokela T, Kvernstuen S, Leung E, Moen T, Porturas F, Skillingstad T, Vorkinn PB and Raffn AG: “Inflow Control Devices—Raising Profiles,” Oilfield Review 21, no. 4 (Winter 2009/2010): 30–37.

Chen et al, reference 5.

43223schD5R1.indd 8 11/17/11 8:29 PM

26 Oilfield Review

various reservoir deliverability and production scenarios. The systems would be especially effec-tive in controlling inflow from high PI zones by using a smaller valve opening, while encouraging low PI zones to flow through a fully opened valve.

The IntelliZone Compact design includes options for three sizes of FCVs, each with fully open, fully closed and two intermediate choke settings. Based on reservoir simulation models,

the valve assemblies were designed using the following selection criteria:•zonalcontrolfordiscretezones•flowbalancefrommultiplezones•crossflowprevention•sufficientcapacityforzonalPIdifferences.

Engineers used integrated field modeling software that provides material balance, nodal analysis and system performance analysis to compare the estimated ultimate recovery for the

wells completed with IntelliZone Compact sys-tems. They studied two production scenarios—potential production gain and downhole water and gas shutoff.

Under the first scenario, compared with pas-sive ICDs, engineers found that active downhole flow control resulted in an additional 15,900 m3 [100,000 bbl] of oil (above). Analysis of the sec-ond scenario, focusing on downhole gas and

> Potential gain in ultimate recovery. Field modeling software providing material balance, nodal analysis and system performance was used to compare estimated ultimate recovery for wells in the PETRONAS-operated S-field. The well was completed with surface-controlled downhole FCVs (blue) and compared with a well equipped only with a passive ICD (green). The FCV-equipped well is projected to ultimately recover 100,000 more barrels of oil than the ICD-equipped wells. (Adapted from Chen et al, reference 5.)

2.4

0

0.3

0.6

0.9

1.2

1.5

1.8

2.1

Jan. 2009 Oct. 2009 July 2010 April 2011 Jan. 2012

Date

Production Gain Analysis: FCV Versus Passive ICD

Oct. 2012 July 2013 April 2014 Jan. 2015

Cum

ulat

ive

oil p

rodu

ctio

n, m

illio

n bb

l

> Flow control configurations. Measuring zonal production with downhole pressure gauges, engineers studied seven control valve configurations for two zones in Well-A2 in the S-field. Case 0 established production with both zones fully open. In Cases 1 and 2, by shutting off production from Zone 2 and then Zone 1, respectively, the operator established the PI and water cut for each zone. Using the results of Cases 0, 1 and 2, engineers were able to discern that because of its low PI, Zone 1 did not contribute any production when both FCVs were fully open. After testing other combinations, the team concluded that Case 3, in which the valve controlling Zone 1 is 33% open and the valve at Zone 2 is 100% open, was the optimum configuration. (Adapted from Chen et al, reference 5.)

Zone 1 Zone 1Zone 2 Zone 2

Case Opening, % Opening, % Tubular, psi Annulus, psi �Pressure, psi Tubular, psi Annulus, psi �Pressure, psiFlow rate,

bbl/d Water cut, %Gas rate,MMcf/d PI, bbl/d/psi

Case 0

Case 1

Case 2

Case 3

Case 4

Case 5

Case 6

100

100

0

33

67

100

100

100

0

100

100

100

67

33

2,094

1,877

2,101

2,095

2,095

2,085

1,951

2,096

1,875

2,102

2,097

2,097

2,086

1,952

2,094

2,105

2,100

2,095

2,095

2,101

2,100

1,179.2

555.4

1,067.6

1,144.4

1,143.4

1,001.9

1,050.6

0.12

21.30

4.85

0.22

0.21

0.44

0.37

0.18

0.05

0.08

0.19

0.18

0.16

0.17

138.9

533.8

2

–230

2

2

2

–15

–148

2,092

1,873

2,035

2,091

2,092

2,082

1,949

2

4

66

4

3

3

2

Case 3 33 100 2,095 2,097 2,095 1,144.4 0.22 0.1922,091 4

43223schD5R1.indd 9 11/17/11 8:27 PM

Autumn 2011 27

water management, indicated that production-ending water breakthrough would occur from the smaller, more permeable reservoir at the well’s heel. By shutting off that zone and opening the thicker, less permeable zone at the well’s toe, production would continue.14

Using pressure buildup survey data, FBHP and surface well tests, an asset team studied pro-ductivity and zonal reservoir deliverability in Well-A2 to better understand the reservoir. Zonal contribution was monitored using permanent downhole pressure gauges, and production was adjusted through FCVs at each zone. After study-ing seven configurations, the asset team deter-mined that 33% and 100% openings on Zones 1 and 2, respectively, created optimum flow (previ-ous page, bottom).

The asset team compared a production pro-file of Well-A1 with one in an offset horizontal well completed in the same sand (above). The former showed a prolonged period of high net oil production while water and gas break-through was deferred. The latter suffered from a fluctuating lower oil rate coupled with acceler-ating water encroachment.

Technical Solution to a Market ProblemFor years, developers of oil industry technology have been stymied by an industry reluctance to adopt innovative solutions. Generally, user hesi-tancy, particularly regarding tools aimed at the upstream sector, has been grounded in a fear that the new system would fail when subjected to the harsh realities of the downhole environment. In

time, misgivings about system reliability have been overcome, and such innovations as rotary steerable systems and expandable casing have become commonplace. The same can be said of the industry’s acceptance of IC technology.

Today, industry recalcitrance about ICs stems from financial concerns among operators uncer-tain about their marginal or maturing assets; operators must see sufficient production increases from remote downhole monitoring and control capabilities to justify the hardware’s initial costs.

The introduction of a modular system aimed at providing the industry with the advantages of a traditional IC at a much lower cost promises to satisfy that requirement. This change in percep-tion will accelerate the adoption of IC technology throughout the industry and, in doing so, signifi-cantly impact how operators view their marginal and mature fields.

With the cost barrier to entry lowered, ICs may extend the life of marginal fields because the technology to control production at the sandface, without interventions, leads to higher net produc-tion and ultimate recovery through more efficient commingling. Similarly, projects with economic scenarios so fragile that they were shelved for fear the cost of probable future interventions would negate net profit may now be brought for-ward. By using ICs in these marginal projects, operators can save on interventions and reduce initial capex for ancillary facilities. The ability to manage reservoir parameters by controlling flow to slow water ingress at the sandface also allows operators to plan smaller surface facilities and reduce water-handling costs, both of which have significant impact on aging or marginal field development plans. —RvF

> Comparing production profiles. Well-A1 (top), equipped with an IntelliZone Compact completion, was able to defer water breakthrough (blue) and reach and maintain a higher net oil production profile (green) than an offset horizontal well (bottom) completed in the same sand. The offset well, however, was plagued by water production that resulted in lower net oil production. (Adapted from Chen et al, reference 5.)

0

500

1,000

1,500

2,000

2,500

Oil r

ate,

bbl

/d

Wat

er c

ut, %

Time, months43210 8765

0

10

20

30

40

50

0

400

200

600

800

1,000

1,200

Oil r

ate,

bbl

/d

Wat

er c

ut, %

Time, months43210 8765

0

10

20

30

40

50

14. Chen et al, reference 5.

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