Multiple questions andintelligent answers

Many Middle East operators see multilateraldrilling as a logical ‘next step’ from horizontaldrilling, which has become commonplace in theMiddle East. Multilaterals are particularlyeffective in complex carbonate reservoirs, butthey have not been widely adopted as a result ofgeneral skepticism over risks, and more practicaldeterrents, such as the engineering of reliable,safe junctions in production strings.

All that is changing. One ingenious solution is aprefabricated, subsurface wellhead assemblythat can be ‘unwrapped’ and installed downhole,splitting the main bore into two smaller, equal-sized, lateral bores and providing a high-pressureseal at the junction.

Asset teams are now turning their attention to theapplication of multilaterals in more hostileenvironments, where economic returns aregreatest, and to the potential for 'intelligent'systems for remote monitoring and adjustment ofreservoir conditions to achieve optimumcompletions.

In this article, Bernard Montaron, Tim O’Rourke,and John Algeroy introduce these rapidlyadvancing technologies.

F or many years, field engineers andoperating companies in the Middle

East have battled with the challenges ofobtaining maximum exploitation ofreservoirs as safely and economically aspossible. During the 1980s,improvements in horizontal technologywere adopted quickly in the region tobring about significant improvements inproductivity. The logical next step,keeping abreast of drilling technology,was to drill multilateral wells thatallowed all the benefits of horizontalwells to be carried forward tomultilayered or ‘stacked’ reservoirs asbranches from a single main borehole.

Seen by some as risky and notsufficiently proven, multilateral drillingmade its somewhat shaky debut in theMiddle East in the mid-1990s. Muchwork has been done since, particularlyto improve the construction andintegrity of multilateral junctions, andtoday’s confidence is evidenced by thehundreds of multilateral wells now in existence.

No revolutions in RussiaMultilateral drilling has its origins inRussia during the 1940s. At that time oilwas a strategic commodity in the SovietUnion and served as a ‘currency’ thatcould be exchanged for grain or otherconsumer goods. High quotas wereimposed on drillers to bore as many holesas possible, in the belief that the moreholes drilled, the greater the chance oftapping a reservoir and the greater thelikelihood of an increase in production.

This supposition was contested by aSoviet innovator and inventor, turneddrilling engineer, Alexander MikhailovichGrigoryan, who believed that more oilcould be produced by following a knownoil sand rather than simply penetrating itwith a number of boreholes. In 1941Grigoryan drilled one of the world’s firstdirectional wells – Baku 1385 – nearly 20years earlier than anyone else. Without awhipstock or rotating drillstring, he useda downhole hydraulic motor to penetrateoil-bearing rock, significantly expandingreservoir exposure and production. Thiswas the first time that a turbodrill hadbeen used for both vertical and deviatedsections of a borehole.

Grigoryan’s pioneering work led toscores of other successful horizontalwells across the USSR and he waspromoted to department head at the

All-Union Scientific Research Institutefor drilling technology (VNIIBT). Hewent on to develop a new, borehole-sidetrack, kickoff technique, and adevice for stabilizing and controllingcurvature without deflectors.

However, his main contribution todrilling technology was still to come.This involved expanding on the theory,previously proposed by Americanscientist L. Yuren, that production couldbe improved by increasing the diameterof the borehole. He stated thatbranching the borehole in theproductive zone “just as a tree’s rootsextend its exposure to the soil” wouldincrease production.

The theory was put to the test in theBashkiria field complex (in what istoday Bashkortostan, Russia) whereGrigoryan drilled Well 66/45, the firstmultilateral well, using turbodrillswithout rotating drillstrings.

In the Bashkiria complex, lateCarboniferous reefs had trapped vast oilreserves. However, most of the wellshad been producing since before 1930and were producing low volumes whenGrigoryan drilled the first multilateral.

In 1953, Grigoryan selectedBashkiria’s Ishimbainefti field to drillWell 66/45 (Figure 3.1). This fieldcontained an interval of Artinskiancarbonate rocks with good reservoirproperties over a wide area. The targetwas the Akavassy horizon, which was aninterval with thicknesses varying from10 to 60 m (33 to 197 ft). Nine brancheswere drilled from the borehole below375 m (1230 ft). This was done withoutwhipstocks or cement bridges, drillingby touch, with each branch extendingfrom 80 to 300 m in different directionsinto the producing zone. The drill bitwas allowed to follow the pay zone intothe most productive areas and curved

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223

425455

473

490521

617 TD

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595 TD595 TD605 TD

617 TD

613 TD

660 TD

582 TD

627 TD

Artinski limestone

Well 66/45

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sure

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pth,

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Figure 3.1: Well 66/45, drilled atBashkiria, nowBashkortostan,Russia, was the firstmultilateral well. Ithad nine lateralbranches that tappedthe Ishimbaineftifield reservoir

automatically to follow the plannedtrajectory. Speed and penetration ratedepended on the hardness of the rockand the power of the downhole motor.

The nine producing laterals of Well 66/45 had a maximum horizontalreach of 136 m from the kickoff point anda total drainage of 322 m (1056 ft). It costabout 1.5 times as much to drill as theother wells in the field, but penetrated5.5 times the pay thickness and, at755 B/D, was 17 times more productive.

Over the following 27 years, a further110 multilateral wells were drilled inRussia – 30 of them by Grigoryanhimself. About 50 of these earlymultilaterals were exploratory and theremainder were for delineation of reefsand channel structures.

Many benefits Until 1980, when ARCO drilled the K-142 dual-lateral well in New Mexico’sEmpire field, there had been noattempts at multilateral drilling outsidethe USSR. This type of drilling wasconsidered too risky and difficult as wellas requiring substantial investment oftime and money. For years, becausethere were few reliable examples ofsuccessful multilateral applications,operators lacked benchmarks foridentifying suitable candidates formultilateral development. Higher initialcosts, the risk of interference betweenlaterals, crossflow, and difficulties withproduction allocations all hindered the

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introduction of multilateral technology.An increased sensitivity to and concernabout reservoir heterogeneities such asvertical permeability also deterredmultilateral development.

Complicated drilling, completion and production technologies, complexand expensive stimulation, slow andless-effective cleanup, and cumbersomewellbore management duringproduction were all seen by operators asfurther obstacles.

Between 1980 and 1995, only 45multilateral completions were reported,but since 1995 hundreds more multilateralwells have been completed and manymore are planned, thanks to improvedtechniques and increased confidence.

Even today there are stillacknowledged risks in multilateral wellssuch as borehole instability, stuck pipe,cementing and branching; but in the1990s, as more multilaterals were drilledsuccessfully, even the simplest wellsconfirmed the potential of this emergingtechnology. The main benefits of thesesuccessful wells were increasedproduction, increased reserves, andoverall reductions in reservoirdevelopment costs.

Traditionally, increasing theproductivity of known reserves has beenachieved by drilling additional wells toincrease drainage and sweep efficiency.Multilateral technology provides therequired increased contact between theborehole and the reservoir withoutdrilling additional wells. By drilling the

main trunk and overburden to thereservoir only once, surface cancontinue to be a single installation withobvious cost savings over the multiwellsituation. Similar benefits can be seen inoffshore and subsea scenarios where alimited number of slots are available,and in onshore locations where surfaceinstallations are particularly expensive.

Multilateral penetrations arecommonly used to increase the effectivedrainage and depletion of a reservoir,particularly where low permeabilityrestricts hydrocarbon mobility or lowporosity limits production flow. Whenindependent reservoirs are targeted,production can either be commingledinto a single production tubing string orproduced separately in multiple strings (Figure 3.2). Multilateral wells are alsoeconomic for rapidly depleting areservoir; effectively acceleratingproduction, shortening the field lifecycle, and reducing operating costs.

Multilateral wells are more efficientthan conventional or horizontal wells inthinly layered formations or significantlyfractured systems, or for specificenhanced oil-recovery situations such assteam-assisted gravity drainage. Theapplication of multilateral technologycan also reduce water and gas coning.

Improving the vertical and horizontaldrainage of reservoirs increasesrecoverable reserves significantly, whileboth capital and operating costs per welland per field are minimized. In fact, thecost of achieving the same degree of

Shallow ordepleted reservoirs

Layered reservoirs

Fractured reservoirs

Figure 3.2: In shallow or depleted reservoirs, branched horizontal wellbores are oftenmost efficient, whereas in layered reservoirs, vertically stacked drainholes are usuallybest. In fractured reservoirs, dual-opposing laterals may provide maximum reservoirexposure, particularly when fracture orientation is known

drainage with conventional wells wouldbe prohibitive in most cases, especiallyin situations such as deepwater, subseadevelopments. The costs of multilateralwells can be recovered over severalreservoir penetrations and, in somecases, the need for infill drilling has beeneliminated completely.

Multibranched wells can tell operatorsa great deal about their reservoirs. Thisis particularly advantageous inanisotropic formations, where thedirections of preferred permeability areunknown. In these cases, lateralbranches can help compensate fornonuniform productivity, withcorresponding economic benefits andenhance formation evaluation.

Classification on the levelIn 1987 in Aberdeen, TechnologyAdvancement-Multilaterals (TAML) – aforum of experts in multilateraltechnology from leading oil companies –set out to define a system of classifyingmultilateral wells in terms of complexityand functionality, which would also relateto difficulty and risk. The complexity ofmultilateral wells is now described on ascale from Level 1 (the simplest)through 6S (the most complex) (Figure3.3), with an additional coderepresenting type and functionality.

The most difficult part of drilling amultilateral well is producing a stablejunction between the main trunk and thewellbore branches. For this reason about95% of the world’s multilateral wells havebeen at level 1 or 2. But in 1998, about50% of the multilateral wells drilled werelevel 3 or 4. Rapid advances inmultilateral connectivity, accessibility andisolation capabilities, together with newjunction systems, are allowing operatorsto select more-complex solutions.

Level 1: Openhole sidetrackingtechnique. The trunk and laterals are alldrilled in openhole, usually in hard rockwith unsupported junctions. Lateralaccess and production control is limited.This is similar to the pioneeringmultilaterals that were drilled in Russia.

Level 1: The main bore is cased andcemented but laterals are in openhole,although sometimes they have a ‘drop-off’liner that is not cemented ormechanically connected to the maincasing. RapidAccess* multilateralcompletion systems that provide selective

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1

2

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4

5

6

6S

SEL – selective SEL – selective

RMC – remote monitoring and controlSEP – separate

NR – no selective reentry

PR – reentry by pulling completion

TR – through-tubing reentry

NON – none

Accessibility

Flow control

REM – remote monitoring

Single bore Dual bore Concentric bore

Figure 3.3: Multilateral configurations and classification by level

drainhole access addressed some of theshortcomings associated with currentmultilateral practices, such as:• uncertain accessibility to the laterals

for workover• casing obstruction and/or reduction of

effective inside diameter• reduced casing stress, running casing

and placement of the window• inflexible drilling sequence.

RapidAccess is designed to beinstalled for either immediate use or for future use in reentry operations.Sidetracks can be performed and thenthe whipstock can be retrieved leavingunobstructed, fullbore casing. Thisallows operators to readily access thesidetracked wellbores remaining.Multiple RapidAccess couplings can beinstalled in casing strings to allow manyreservoir penetrations for optimum fielddevelopment. In these cases, depth andorientation can be determined by amonitoring-while-drilling survey aftercementing, or by coiled-tubing orwireline conveyed USI* UltraSonicImager surveys (Figure 3.4).

The complete systemThe complete RapidAccess System hasseveral main components:• The indexed casing coupling (ICC), a

casing nipple with selective key profilesto accommodate sidetracking andcompletion tools. It uses a muleshoeorienting profile to receive a key thatrotates the whipstock or reentrydeflection tool (RDT) assembly to thedesired orientation relative to themuleshoe’s orienting keyway

• The selective landing tool (SLT) is alocating and anchoring device. It hasselective keys that allow it to bepositioned in the profile of the desiredICC along with its attached tool suchas a whipstock, RDT and orientationconfirmation assemblies

• The RDT assembly is recoverable byovershot. It resembles a smallwhipstock and acts as a guide forrotary drilling, running liner,completion equipment running andworkover operations.Drillers can also carry out window

milling in existing wells usingconventional retrievable whipstock orcement plug techniques. Premilledcasing subs are sometimes employed to

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Window fromUSI log

Index casingcouplingfrom USI log

Window toICC spacing

Figure 3.4: USI log showing an indexed casing coupling (ICC) and a window milled in 7-in., 26-lbm/ft casing using a downhole motor. This log was run to verify the length of a full-gaugewindow. A USI log can be run in most common drilling fluids

avoid the increased risk of milling in situ.The Level 2 RapidAccess process isshown in Figure 3.5.

Level 3: Both connectivity and access arepresent in Level 3 multilaterals. Themain trunk and laterals are cased,although only the main bore iscemented. There is no hydraulicintegrity or pressure seal at the lateral-liner-to-main-casing junction but there ismain bore and lateral reentry access.

The Level 3 RapidConnect*multilateral completion system(selective drainhole access andconnectivity) provides high-strengthjunctions – where lateral liners areanchored to the main bore by liner

hangers or other latching systems – andis important in wells where sand or shalemay affect well stability.

In Level 3 systems, upper laterals canbe isolated at the junction to allowproduction from lower laterals. Selectiveaccess to laterals is achieved by theoriented diverter positioning.

A complete Level 3 RapidConnectsystem has several main components(see Figure 3.6):• selective landing sub (SLS)• template• connector.

The most common completionperformed in Level 2 and 3 wells isuncemented, predrilled or slotted linersand prepacked (but not gravel-packed)screens. Anadrill uses a drop-off linercompletion design in which the top ofthe liner in the lateral is immediatelyreleased outside the casing exit througha hydraulic sub. External casing packersare often used in the drop-off linercompletion assembly to isolate zones,

anchor the liner top and facilitatereentry access to the liner.

Another mid-tier approach tomultilateral completion offers onlyindividual hydraulic isolation of a lateral.In this case, laterals are drilled usingwhipstock sidetracking procedures, andany completion performed in the lateraluses a drop-off liner. Conventionalcasing packers in the main casing withtubing between them – straddle packers

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Figure 3.5: Level 2 RapidAccess 1. The main wellbore casing is run with indexed casing couplings (ICC) as integral components. 2. The main wellbore casing is cemented. 3. The lowerbranch is drilled, completed and isolated with a retrievable bridge plug. 4. The coupling orientation is determined from a USI log or by running a selectivelanding tool (SLT) with Slim 1* slim and retrievable MWD system in the universal bottomhole orienter (UBHO). The coupling can be cleaned during this tripand a gel pill may be spotted in the kickoff section to suspend debris. 5. The whipstock is aligned with the SLT key and run into the well. The assemblyautomatically aligns and latches and the milling tool is released from the whipstock. 6. A casing window and short section of pilot hole are cut with thespecial milling assembly powered by a downhole motor. 7. After a lateral is drilled to depth, the well may be left openhole or as a simple cemented or drop-off liner run. The SLT is released and the entire assembly is retrieved. The hole is cleaned out and the bridge plug removed

8. The process is changed for a cemented liner by replacing the full-size whipstock with a smaller diameter reentry deflection tool (RDT) that is run andlatched into an ICC. 9. The bottomhole assembly (BHA) is run and a lateral branch is drilled. 10. A liner is run into the lateral and may be cemented back intothe main casing. 11. The liner running tool is released, the hole cleaned up by reverse circulating and the liner running tool is pulled out of the hole. 12.After the lateral is completed the RDT is retrieved by releasing the SLT. RDT and SLT are pulled from the well. 13. The lower wellbore section is cleaned out,the isolating bridge plug retrieved and the main bore is ready for completion

8 9 10 11 12 13

SLT

RDT

– are used to isolate each of the lateralshydraulically. Production from thelaterals is controlled with sliding sleevesand other flow-control devices. This isan inexpensive and relativelystraightforward multilateral completionmethod that was proven in the NorthSea and is now being adapted fordeepwater, subsea wells.

The critical technology in thesecompletions is operation of flow-control

1 2 3 4

Slim 1MWD

5 6 7

Gelledfluid

SLT

ICC

devices downhole. Schlumberger Camcointelligent well technology is nowcapable of activating and controllingthese flow control devices remotely.

Level 4: In Level 4 wells, both main boreand laterals are cemented at thejunction. This provides a mechanicallysupported junction with the lateralcemented to the main casing, but nohydraulic integrity. The sidetrack isusually achieved by whipstock-aidedmilling of the casing windows, althoughpremilled windows may be used in somecases. There is no pressure seal at thejunction, but main bore and laterals havefullbore access. Level 4 technology iscomplex, high-risk and still underdevelopment, but it has been successfulin multilateral wells worldwide.

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Level 5: The techniques used in levels 3and 4 for lateral connections are alsoused in Level 5, but additionalcompletion equipment is employed tocreate a pressure seal across thejunction of the lateral and the maincasing. Cement is not acceptable forhydraulic isolation of the junction.Isolation is achieved using auxiliarypackers, sleeves and other completionequipment in the main casing bore tostraddle the lateral junction withproduction tubing. This arrangementprovides reentry to both the main boreand the laterals.

Level 6: Level 6 multilateral techniqueswere first evaluated by Schlumberger in1995 with a system developed by Anadrill,Camco and Integrated Drilling Systems.There has recently been much researchand development effort concentrated onsealing for hydraulic isolation andpressure integrity for Level 6 junctions.(See separate panel, overleaf.)

Level 6S: This is a subset of Level 6 thatuses a downhole splitter, or subsurfacewellhead assembly to divide the mainbore into two smaller, equal-sized,lateral bores.

Multilateral technology is now focusedon new Level 6 designs. A major part ofthis development centers on the mostdifficult aspects of multilateraltechnology, hydraulic isolation andintegrity at high pressure.

Starting at the bottomWhen planning a multilateral well, thefirst step is to establish the desiredposition of each lateral in its producingformation. The design is then workedback until the trajectories of all thelaterals, the main bore up to thewellhead, have been determined. Thisprocess must consider reservoirproperties such as the rock-stress regimeand the geometries of the productivereservoir zones. Information from varioussources, including 3D surface andborehole seismic data, well logs and coreanalyses, formation and well testing, fluidproperties and production histories,must also be examined.

Permeability differences and stressanisotropy are important factors indeciding whether laterals should bevertical, horizontal or slanted. Forexample, slanted and horizontal lateralsare most productive when orientedperpendicular to natural fractures, andslanted laterals are best when verticalpermeability is much less thanhorizontal permeability.

Geological and petrophysical modelingtools like INFORM* Integrated ForwardModeling help to identify risks alongproposed trajectories by providing initialpetrophysical descriptions. Theseforward models are completed usingsynthetic log data sets generated by 2Dand 3D LWD measurements.

Connector is partially engaged

Connector is fully

engaged

Template

Connector

Uppercompletionpacker

RapidConnectconnectorRapidConnect

template

Selectivelanding sub

Lowercompletion

packer

Selective throughtubing access

3. The upper part of the completion is run and landed in the PBR of the template. This provides ahydraulic isolation around the junction. 4. An isolation sleeve is run to hydraulically seal andisolate the lateral from the main bore. 5. To access the lateral a selective through tubing access(STTA) tool is run and landed in the nipple of the template

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Figure 3.6: Level 3 RapidConnect. 1. Run the template attached to selective landing sub (SLS).Template aligns with the milled window. 2. Run the connector to engage with the polished borereceptacle (PBR) of the drop-off liner, then the top of the connector lands in the template and theconnector running tool is retrieved

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Opening tool at full-open position

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Expand legs of junctionReal-time monitoring of leg geometryPOOH expansion tool

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Run in hole junction- expansion tool on electric line and verify orientation

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Run 9 5/8-in. casing with RapidSeal attached

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Drill 121/4-in. boreholeUnderream 171/2-in. hole

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Install a cement retainer on electric line

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Drill out cement retainer and cement to top of junction

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Run the drilling deflector and orient it in the profile

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Cement the junction using standard, dual wiper plug

Close-up of fully extended piston assembly

17-in. ID

121/4-in. ID

Compressedjunction

Reformedjunction

RapidSeal geometry

No leaks at Level 6

An exciting new development for Level 6 junction integrity that comes from countless staff hours of research and analysis isthe RapidSeal* multilateral completion system providing selective drainhole access and connectivity with pressure-sealedconnection. This junction is made at surface, deformed to fit inside 13 3/8-in. casing, then reformed when it reaches its positionin the well.

The RapidSeal junction is run as 9 5/8-in. casing and is formed by integrating two sections of 7-in. casing below the 9 5/8-in.casing. This design features strong but highly ductile components. If the outlet sections were installed side-by-side, thediameter of the whole assembly would be too large for the 13 3/8-in. casing. In the RapidSeal design, the two outlet sectionsare plastically deformed so that the effective diameter is just 12-in. and runs easily in 13 3/8-in. casing.

When the junction is in place in the wellbore, the RapidSeal outlets are slowly and uniformly reformed using wireline toolswith surface control and monitoring that allow minimization of stresses.

The best drilling and completionstrategy is to construct laterals from thedeepest branch up. In this way, thewellbore above the branch point remainstrouble-free whatever happens below.

Drilling multilateralsThe earliest multilateral wells, like thosedrilled by Grigoryan in 1953, were, interms of the present-day classification,levels 1 and 2 – openhole completions inhard rock. Since then, directional drillingtechnology has become more complex.This reflects the demands for higherlevels of multilaterals as asset managersgain more comprehensive andsophisticated information about reservoirproperties and geological conditions.

The tendency is for small-diameterboreholes to be drilled to reduce cost,and multiple, slimhole horizontalreentries to be drilled from small-diameter wells to further increasereservoir exposure. Coiled tubing is alsoemployed to drill multiple radials fromthe main bore. Coiled tubing drilling isfrequently used to remove near-wellboreformation damage in order to increasereservoir flow potential or for drillingdrainholes to replace perforations.

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Further cost savings are achieved bydrilling short-radius wells with buildangles up to 1.8°/ft, a method that canchange a well’s orientation from verticalto horizontal in just 50 ft. There is lessformation damage in these wells, andthey are faster and therefore moreeconomical to drill for many reasons,including smaller drilling fluid volumesand reduced rig time.

Among the most challenging aspects ofmultilateral drilling today, is thedevelopment of suitable reentrytechniques. These must go far beyondtraditional sidetracking methods in orderto keep pace with advances in operationssuch as stimulation, acidizing andperforating. The increasing complexity ofmultilateral configurations mean thatreentry to a single branch or reentry toone of several branches at a commonlevel presents one of the greatestdifficulties. Further factors to considerwhen selecting a reentry techniqueinclude the type of completion (whetheropenhole or cased), hole size, vertical-to-lateral build rate and the need tohydraulically isolate the lateral.

The first step in a reentry operation isto recognize the reentry point. The nextstep is to enter the lateral. This can beachieved by running a tool on coiledtubing that rotates to reentry depth. Thetool is designed with a bend on the endthat registers a weight change when itenters a lateral window. The VIPER*slimhole CTD MWD and motor systememploys a bottom orientation sub thatlocates and accesses laterals. Anothermethod is to run a whipstock diverter,that orients in a predefined tubing orcasing profile nipple to accurately locatethe diverter at the lateral opening. Thistechnique is used where completionequipment is specifically designed forthrough-tubing reentry into laterals.

Wellbore managementIn production engineering and theoperation of multilateral wells, the keyconsiderations are whether a well needsartificial lift, and the degree to whichimposed formation pressure drawdownis affected by frictional pressure dropinside the well. For example, short,

Run the deflector in the junction oriented to the second leg and drill second lateral

Run the 41/2-in. linerhanger and linerinto the lateral

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POOH deflector and run the DualAccess system to plumb each leg to the main bore completion

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Application:Multilaterals requiring sealing junction

Features:Structural and hydraulic integrityControlled opening processSymmetrical formingOne wireline trip to form junction

RapidSeal Level 6 junction

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Run short catch liner hanger and 41/2-in. liner string in the first lateral

Install a slickline plug in the nipple directly below the hanger. This isolates the lateral from the rest of the well

Retrieve the deflectorRepeat the process on other lateral and complete

opposed laterals are preferable to a long,single horizontal well in one direction ifdrawdown is about the same as pressuredrop in the wellbore. Conversely, ifdrawdown is several hundred poundsper square inch, or more, a singlehorizontal leg may be adequate.

Selective wellbore control is providedby three basic completion configurations:• individual production tubing strings

tied back to surface• commingled production• commingled production from

individual branches that can bereentered or shut off by mechanicalsliding sleeves or plugs.As more parts of a reservoir are

exposed to wellbores, careful reservoirmanagement becomes paramount. Forexample, laterals that drain multiplelayers or different formations willrequire selective management if porepressures and fluid properties differwidely between zones. The degree ofcommunication between the drainageareas of individual laterals may be themost important reservoir engineeringissue in multilateral applications.

Reservoir exploitation strategies oftendefine the best configuration for thecompletion. In selecting the degree ofconnectivity, isolation and access, threeof the most commonly usedconfigurations are: • drain several stacked layers that may

not be in communication• drain a single layer in which areal

permeability anisotropy is critical• drain geologic compartments that

may not be in communication.A vertical main bore is the most

suitable for draining stacked layers. Thecommingled production from stackedlaterals can be compared withcommingled production from two ormore layers in a vertical well, except thateach lateral has higher productivity thana vertical completion through the samelayer. In addition, control of verticalinflow, or conformance, is easier becausethe productivity of each lateral is roughlyproportional to its length. Vertical flowconformance avoids differential depletionunder primary production, and unevenwater or gas breakthrough undersecondary production.

Future multilateraltechnologyThere are still different opinions withinthe industry on the best approach toimproving and optimizing multilateralconnectivity, as well as on newcompletion strategies to connect morelateral wellbores with the productivereservoir intervals.

Firstly, the casing windows need to beimproved for ease of drilling andreentering multiple lateral drainholes.Many believe that a technique must bedeveloped to seal casing windowconnections, providing pressureintegrity at the junction. To achieve this,a great deal of work is being done toperfect a reliable mechanical seal or newchemical sealants for Level 6 wells.Other experts, however, maintain thatthe vast majority of multilaterals exit themain bore into the same reservoir,where the pressure differential at thejunction is negligible. In that case,priority should be given to developingfit-for-purpose junction integrity toincrease production and the ability tomanage laterals over the life of a well.

Downhole construction of lateraljunctions has associated problems suchas generating debris and lack ofcementing options. Surface construction,as in Level 6S wells, is debris-free butcan only be done for new, shallow wells.

Opinion is also divided on the subject ofcasing windows. Downhole constructionfavors milling standard casing byreferencing inexpensive casing profilenipples or packers. Multiple nipples can bedesigned into casing strings, permittingoperators to choose sidetrack locationswhen they are ready and providing areentry sleeve reference as well. However,operators can also run a composite casingsection (Figure 3.7) with a profile nipplebelow it from which the drilling whipstockand lateral entry system sleeve can bespaced. Although there is no milling,casing strength is compromised.

Premilled windows or casing stockthat has removable sleeves or is encasedin drillable material are promoted bymany to provide tensile strength withouthaving to mill downhole. As withcomposites, the whipstock and lateral

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4 1/2-in. upper tubing 13 3/8-in. casing

Top of liner3680ft, TVD

M-seal sealant

Window bushingassembly

Top of window3858ft, TVD

7-in. composite joint

Hollow whipstockOrienting latch

Multilateral packerOrienting nipple

Retrievable packer

TD 8439ft, MD

4 1/2-in. predrilledcasing

6 1/8-in. open hole6 1/8-in. open hole

9 5/8-in. casing 7-in. liner 4798ft, MD

TD 8439ft, MD

Figure 3.7: Composite casing window

entry system sleeve are deployedthrough casing nipples. Generally, lateralcasing is allowed to protrude into themain casing, where it is cemented inplace and then milled or washed over torestore full main-bore diameter. Bothmechanical and pressure-tight tie-backsare being developed.

Other technical issues need to beresolved, including the management andmonitoring of production. A newgeneration of intelligent downholetechnologies has long been heralded as thefuture of the upstream petroleum industry.

Schlumberger is involved in thedevelopment of several new, intelligentcompletions-related products that weredeveloped in cooperation withoperators. A systems-integration-typeapproach was taken, which focused onworking with operators to developcustomized solutions for problemsspecific to a given reservoir. For thispurpose, in October 1999 Schlumbergeropened its Rosharon Center toaccommodate its Advanced CompletionsGroup. Intelligent completions mayultimately yield remotely operatedsubterranean and subsea factories withoil and gas as the finished products.

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Multilaterals in the Middle EastMultilateral drilling began in the MiddleEast during the mid-1990s, and morethan 200 horizontal wells have beendrilled in the region. In the United ArabEmirates, Zakum Field Development Co.(ZADCO) and its operating companyAbu Dhabi Marine Operating Co.(ADMA-OPCO) are developing Zakumfield, one of the largest in the region.ZADCO’s experience and expertise inmultilateral technology are vital to thisdevelopment program.

Zakum field, discovered in 1963, issituated offshore in the Arabian Gulfabout 80 km (50 miles) northwest ofAbu Dhabi. The producing formation is alarge Cretaceous limestone with variouslayers in three main stacked reservoirs(Figure 3.8). Development began in1977 with conventional drilling.Horizontal drilling was introduced in1989, and extensive multilateral drillingcommenced in 1994 as a result ofimprovements in horizontal technology.The first multilateral well was completedin March 1995. Encouraged by asignificant production increase, ZADCO

decided to develop the stackedreservoirs using a combination ofhorizontal and multilateral drilling. Todate, 39 dual-lateral and 45 multilateralwells have been drilled and completed,and more are planned.

Initially, the complex of reservoirs waspenetrated by a deviated wellbore andthen by a single horizontal drainholethrough most of the layers. These twotechniques increased borehole exposureto the reservoir and allowed theoperators to produce oil from thehighest permeability layers. However, oilin less permeable layers was left behindwith subsequent substantial loss ofreserves. Drilling separate drainholes forsubzones provided a better opportunityfor stimulation and enhanced productionbecause each horizontal hole wasconnected directly to the main wellbore.

Drilling multilateralsLevel 2 multilateral wells at Zakum field(Figure 3.9) begin with a deviated section,having a maximum inclination of 55° forease of wireline operations. Surface andintermediate casing are cemented, andwells are deepened to 95/8-in. productioncasing or 7-in. liner depth just above lowerreservoir. Using a retrievable whipstock, acasing window is milled near the topreservoir and the upper drainhole isdrilled using intermediate- and short-radius techniques. The whipstock isremoved and the next horizontal hole iskicked off below the production casingstring. Wellbore inclination is increased to

Zakumfield

Bahrain

United ArabEmirates

Qatar

less than5md

less than5mdWest East

I1, I2I3I4I5I6I7

IIIA

IIIBIIIC

IIIDH

IIIJ

IIAIIBIICIIDIIEIIF

AbuDhabi

Saudi Arabia

Figure 3.8: Zakumfield geology

30-in. casing133/8-in. casing

II (dense)IA

IIAIIBIICIIDIIE

95/8-in. casing

Figure 3.10: Steppeddrilling profile

Figure 3.9: A typicalZakum field

multilateral well

30-in. casing133/8-in. casing

II (dense)IA

IIAIIBIICIIDIIE

95/8-in. casing

8 1/2in. hole

horizontal, and a lateral is drilled into thereservoir. The deviated wellbore iscontinued from the last kickoff point, andanother lateral is drilled using the sameprocedures. Specialized or customprofiles, like a stepped pattern thatmaximizes footage in certain intervals,can also be used (Figure 3.10).

Curvature ranges from 6°/100 ft to10°/100 ft, depending on reservoirrequirements and whether medium- orshort-radius techniques are being used.Horizontal sections are typically 750 to3000 ft, with hole size normally 6 in.Planned trajectories in thin oil layers arefollowed using MWD and LWD.

Several factors contribute to asuccessful multilateral well:• Zonal isolation – The pressure

difference between the two reservoirsmeans that it is extremely importantto isolate zones between upper lateralsand lower drainholes. Cementadditives and operations are optimizedto improve primary cement bond andsometimes external casing packers areused on the production casing

• Window milling – Accurate andefficient positioning, setting andremoval of whipstocks are key tosuccessful multilateral drilling. Morethan 50 horizontal wells have beensidetracked using retrievablewhipstocks. Until very recently, aminimum of three trips was necessaryto install a retrievable whipstock, sonew single-trip whipstocks are awelcome step forward (Figure 3.11).

• Drilling dense barriers – Drillingtechniques are selected to minimizedrilling in the dense, low-permeabilityrock that separates the porous layersof Zakum field and to maximize thehorizontal footage within the reservoirzones for optimum oil recovery. Eachtechnique presents its own challenges.Stepped drilling through variousreservoir layers is operationallydifficult because of the low angles ofincidence when trying to crossbarriers. Another technique, drillingseparate drainholes for each reservoirzone, can present postdrilling

problems associated with productionmonitoring and stimulation ofindividual drainholes

• Early water breakthrough –Multilateral wells are drilled to avoid ordelay water breakthrough by selectingthe horizontal section position andlength within desired layers based onspecific reservoir requirements

• Low-departure targets – Anotherchallenge was drilling multilateralwells with targets less than 1000ft(305m) from the platform wellheads.Various options were considered fordrilling the deviated sections of theselow-departure multilateral wells, but ahook-shaped profile was found to bethe best. This well profile can bedesigned to have sufficient inclinationto use previously successful, medium-radius drilling. Several hook-shapedmultilateral wells with four drainholesfrom the main bore were successfullydrilled and completed

• Low-permeability zones – Multilateralwells are particularly effective forexploiting thin reservoirs. One of thefield’s reservoirs that held substantialoil in place was an 8-ft (2.5m) thickzone with 6-md permeability. Twobranches were drilled in differentdirections to increase the drainage area

and improve production. The numberand geometry of the branches weredictated by reservoir characteristics

• Staying within targets – Anotherchallenge for drilling multilateral wellsis to correctly position and maintainhorizontal sections within existingsweep patterns. Since branches drilledin opposing directions were found to beoptimum, severe left- and right-turningtrajectories were drilled at Zakum fieldto achieve the required reservoirexposure. A significant increase inproduction rates was observed in wellsdrilled in this manner

• Multiple holes from a single casingwindow – Several drainholes weresuccessfully drilled from the samemain borehole after exiting casing inreentry and new wells. Thisprocedure can avoid the time andexpense of multiple easing exits, butdoes limit the ability to monitor andstimulate laterals

• Stimulation of multilateral openholes– Production from reservoirs I and IIat Zakum field is kept separate usingdual-tubing completion. Currentthrough-tubing stimulation systemsaccess each drainhole selectively, socommon practice is to pumpstimulation treatments down the

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Step 1

Run multilateralpacker onstarter millassembly

Set packer

Shear starter mill

Begin millingwindow

Completemilling ofwindow

Step 2 Step 3

Figure 3.11: Window milling with a single-trip whipstock

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production tubing from surface.Wherever possible, coiled tubing wasrun through the production tubing toselectively treat individual openholelaterals in the main reservoirs.Permeability varies in each productive

layer, so acid must be diverted across allintervals where coiled tubing is unableto reach total depth. The diversiontechniques in use do not alwaysstimulate the desired number of laterals,and production logs are being used tofurther evaluate stimulationeffectiveness as well as design andprocedural modifications.

Future multilaterals Multilateral drilling in Zakum fieldprovided an opportunity to improverecovery and manage field productionmore efficiently. More than 80 new andreentry Level 1 and Level 2 multilateralwells (from single and dual laterals up toseven laterals) have been successfullycompleted. These have boostedproduction from the field’s thin, low-permeability reservoirs, wheredevelopment by deviated or verticalwells had not been effective. The bestresults were achieved from horizontalwells with branches in opposingdirections. One of the remainingchallenges is to perform independentoperations in each lateral to overcomezonal isolation difficulties.

Cost analysis has shown that short-radius drilling is more expensive, but therapid growth in short-radius drillingtechnology has reduced the cost per footof horizontal drilling by 30% afterdrilling 27 horizontal sections in 10wells. Generally, the higher costs arejustified by improved productivity.Lower costs, resulting from steerabledrilling technology, have encouragedZADCO to continue drilling multilateralhorizontal wells.

Remote-control reservoirsToday, 3D seismic and horizontal drillingare practically routine operations forwells drilled in the Middle East.Multilateral drilling, although still beingtechnologically refined, is also becomingmore commonplace. Meanwhile, assetteams are turning their attention to theapplication of multilaterals in morehostile (e.g., deep-sea) environments,where economic returns over individualwells are greatest, and to the potentialfor ‘intelligent’ systems that monitor andadjust to reservoir conditions to achieveoptimum completions.

The focus at the Rosharon AdvancedCompletions Center in Texas is onreservoir-driven and custom solutionsthat require a lot of early cooperationwith the operator. One of the main aimsin modern completions is to be able tomanipulate production and to performwell intervention downhole. Puttingsensors downhole means that real-timeor near real-time measurements can becollected and input to computerprograms that help to analyze thereservoir and production operations.Monitoring in this way enables engineersto control, for example, watermovements and to ensure maximumsweep efficiency.

Considerations forcompetent completionsMany of the factors that had to beconsidered in ‘standard’ completiontechnology have led to the developmentof new equipment and advancedtechniques over recent decades. Anumber of operations must be carriedout effectively for successful production.These include cementing, casing,installing production tubing, packers andother production equipment, and also

perforating zones of interest. Of course,the completion design must addressreservoir type, drive mechanism, fluidproperties, well configuration and anyother complications that might exist,such as the production of sand orparaffin deposition.

As well designs become morecomplex, well intervention isincreasingly risky and it is necessary tofind better ways to optimize productionin the new operating environments.Surface intervention is difficult, anddeepwater or subsea intervention evenmore so. Completion technology thatrelies on surface flow-control valvesalone imposes significant limitations,since it is impossible to be selectivebetween production from multiple-flowunits in a single wellbore or one lateralof a multilateral well. Neither canproduction from commingled flow unitsbe controlled in the absence ofdownhole flow technology.

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In standard completions, the absenceof downhole monitoring limits theavailable reservoir data. Measurementssuch as total flow rate, wellheadpressure and fluid composition can betaken at surface, but the conditions at aproducing zone and the contributionsfrom individual zones can only beprecisely determined by ‘smart’measuring devices installed downhole.Well tests and production loggingprovide data from discrete points, ratherthan a continuous history, and well testsmean costly interruption of production.

Clearly, the ability to adjust downholeequipment in response to real-time dataminimizes the possibility of productionsurprises that can happen despite thebest completion technology practices.

Ingredients of intelligentcompletionsAn intelligent completion is defined asone that allows operators to bothmonitor and control at least one zone ofa reservoir. Monitoring is achieved bydownhole gauges that continuouslyrecord data for downhole pressure,temperature and flow rate. Control is byvalves operated remotely from thesurface (Figure 3.12). The main aim ofintelligent completion devices is to usethem to safely, and reliably integratezonal isolation, flow control, artificial lift,permanent monitoring and sand control.The result will be the ability to address asituation before it becomes a problem.

The successful downhole use ofsurface-operated, flow-controlequipment depends upon reservoir datathat facilitate decisions about theefficient production of reserves. In anordinary completion, well tests,production logs and seismic surveysprovide only static snapshots of thereservoir. These might not alwaysrepresent the reservoir’s normal behavioror capture events that require correctiveaction. In complex well configurations,such as multilateral wells, productionlogging is difficult. Simply getting to thereservoir to acquire data can be risky,time-consuming and expensive.Workover operations, such as pluggingand abandoning a zone, can bechallenging and costly because aworkover rig must be brought to thewellhead and remediation equipmentplaced in the wellbore.

Retrievablevalve

Hydraulicactuator

AA

Productiontubing

Control linesto surface and

lower zones

Section A–A

Section B–B

BB

Figure 3.13: Hydraulicwireline-retrievableflow control valve

Sensors Software Actuators Intelligentcompletion

Figure 3.12: The elements of an intelligent completion

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Permanentgauges

Electricactuator

Choke

Figure 3.14: Electrically controlled valve with aninfinite number of positions

Electrically and hydraulicallyoperated, tubing-retrievable flowcontrollers also have no practical depthlimitations and can include instrumentsto measure formation temperature,pressure and flow.

The reliability of flow-control devicesis a critical concern because, likepermanent gauges, they are meant tolast for the life of the well and, with the

Reservoir engineers first developedthe idea of monitoring downholeconditions in onshore wells in the 1960s.The downhole gauges they used wereactually modified wireline equipment.Significant developments in permanentmonitoring technology have sinceresulted in permanent downhole gaugesthat are incorporated in today’sintelligent completions to allowcontinuous data acquisition. Permanentgauges have established an impressiveworldwide track record for reliablymonitoring downhole pressure,temperature and flow rate. Real-time ornear real-time pressure, temperatureand flow-rate data show the continuousvariations in reservoir performance.

While second-by-second datacollection might seem excessive duringroutine production operations, theabundance of data ensures that high-quality analysis can be performed whenneeded. Once reservoir behavior hasbeen carefully evaluated, the reservoirteam can decide if or when adjustmentsto the completion might be appropriate,using actual data rather than assumedinput values in reservoir simulations.Operations can continue while downholeconditions are adjusted using remotelycontrolled valves operated from surface.

Field-proven flow-control valves arehydraulically actuated, variable-windowvalves that can be incrementallyadjusted to control the flow area moreaccurately. In contrast, their less reliablepredecessors could only operate in thefully closed or fully open state.

The flow-control valve is mounted in aside-pocket mandrel, or a cylindricalsection offset from the tubing, so thatthe valve can be retrieved by wireline orslickline if necessary (Figure 3.13). Byapplying hydraulic pressure, a variablewindow valve can assume one of sixsequential positions to set the rate atwhich fluids are produced from theformation into the tubing, or injectedfrom the tubing into the formation.Check valves prevent crossflow betweenthe reservoirs.

An electrically controlled valve thatgoes a step further and allows infinitelyvariable adjustment between the openedand closed positions is currently underdevelopment (Figure 3.14).

exception of wireline-retrievabledevices, are not usually recovered forrepair, maintenance or post-mortemfailure analysis. These demands makelong-life field trials impractical and theidentification of risks through othertechniques essential. Simple, robust andfield-proven equipment is fundamentalto the designs. Therefore flow-controlvalves incorporate proven technology,

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• Commingling production in stackedreservoirs with potential for crossflow,or in areas where governmentregulations require separateaccounting for production fromseparate hydrocarbon zones. In fieldsundergoing secondary recovery suchas waterfloods, flow-control devicesand permanent gauges can be used to maintain critical injection rates.This will help to avoid prematurebreakthrough caused by injectingfluid too rapidly and to prevent theinefficient displacement of reservoirfluids caused by an injection rate thatis too low.Clearly, remote monitoring and flow

control can address complicationspresented by multiple reservoirs,multiple fluid phases, formations thatare sensitive to drawdown pressuresand complex well configurations.

such as hydraulic motors fromsubsurface safety valves. Newlydeveloped components have passedrigorous qualification tests.

Initially, it might be difficult to choosefrom the dozens of options forcompleting a wellbore in a new reservoir.Until the reservoir has beencharacterized to the satisfaction of theoperations team, completion specialistsrecommend ensuring flexibility;continuously acquiring data and thenusing reservoir-modeling tools tocompare predictions with actual results.

First fields with flow controlshow the benefitsAt present there are no examples ofadvanced completion technology beingapplied in the Middle East. Indeed,fewer than 20 advanced completionshave been deployed around the world,but where they have been installed,these systems are increasing recoveryand proving their economic andoperational value.

In major fields, reserves that mighthave been left in the ground are beingrecovered through the use of flow-control devices. For example, a thin oilzone under a large gas cap in the massiveTroll field, offshore Norway, is beingdrained by extended-reach or horizontalwells that contact a greater area of thereservoir than vertical wells and reducethe drawdown per unit area to avoidpremature gas coning. At the same time,downhole, gas-lift technologysignificantly reduces the costs associatedwith injection from the surface.

In another example of intelligentcompletions, an innovative extended-reach, multilateral well in the Wytch Farmfield in Dorset, UK (Figure 3.15) uses flowcontrol to produce from two differentsections of an oil reservoir where water isexpected from one of the zones.

This installation was prompted byproblems that had been encountered inthe original well. The solution was aflow-control device developed by Camcothat had been successfully installed inthe Troll field. The operators nowanticipate that an additional 1MM bbl ofoil will be recovered that mightotherwise have been left in the ground.

Currently, advanced completions areused in areas where interventions aremost costly – deep-sea, arctic andenvironmentally sensitive locations –which also tend to have more complicatedwells. To date, five valves have beeninstalled in the Troll field and three valvesin the Wytch Farm completion, all ofwhich are currently in operation.

Other applications of flow-controlvalves and permanent gauges include:• Downhole gas production and

autoinjection, which may eliminatethe need for gas-production and gas-injection wells (Figure 3.16). Inaddition to economic benefits, this practice also reduces theenvironmental impact

Poole

Poole Harbour

Isle of Purbeck

Well M-2TD location

UKLondon

Poole

Surfacewellsite M

Bournemouth

Sherwood sandstone reservoir

Figure 3.15: WytchFarm field.Significant oilreserves lie beneaththe bay and aredrained by extended-reach wells

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Figure 3.16:Producing gas-freeoil. The left wellboreproduces gas. Themiddle wellbore is agas-injection well.Downhole gasproduction andautoinjection usingflow-controltechnology, shownright, can replacecostly surfacefacilities and gas-injection wells

Producer Autoinjector

Injector

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Planning the plumbingMonitoring and controlling flow from thesurface are the first stages in optimizingreservoir plumbing. Ideally, futurereservoir management projects willroutinely involve observation and datagathering, interpretation andintervention (Figure 3.17).

Dynamic updating of the reservoirmodel, using feedback from real-timemonitoring, maximizes the value of thedata, and allows operators to determineoptimum flow, and to make informedadjustments to downhole valves thatcontrol flow from the reservoir.

The Reservoir Dynamics and Controlgroup at Schlumberger-Doll Research,Ridgefield, USA designed a laboratoryexperiment to assess the impact of real-time data collection and flow control onrecovery. The experimental apparatussimulates a deviated well in an oilreservoir near an oil–water contact(Figure 3.18).

The Berea sandstone reservoir in theexperiment was saturated with freshwater to represent oil in an actualreservoir. The ‘oil’ was displaced by saltwater representing connate water in anactual reservoir.

Reservoir monitoringand control- Sensor type and location- Flow-control equipment and location

Project goals and constraints- Maximize recovery- Maximize net present value- Flow rate- Pressure- Water cut

Simulation and optimization algorithm

Shared earth model

Figure 3.17: The key elements of an optimization strategy

Figure 3.18:Simulating adeviated well withthree valvescontrolling flow fromthe producing zones.The reservoir isinitially saturatedwith fresh waterfrom below,simulating anunderlying aquifer

The ‘well’ has three flow-controlvalves. When the valves were openedfully, ‘oil’ production was followed byearly ‘water’ breakthrough at thedeepest completion in the wellborebecause this part of the well is closest tothe ‘oil–water’ contact and is the path of

least resistance. Consequently, thereservoir was poorly swept.

An optimal production strategy wasthen designed using the model that had been prepared for thelaboratory reservoir. A simulation,performed with ECLIPSE* reservoir

simulation software, was linked to anoptimization algorithm that combinedthe objective of maximum recovery withpractical constraints, such as thereservoir pressure at each part of thewellbore, a fixed total production rateand maximum water cut. The simulationshowed that more oil could be recoveredby varying offtake in different segmentsof the well. By adjusting the valves in thenext phase of the experiment, more ‘oil’was indeed recovered because the‘water’ front approached the wellboreevenly rather than breaking through onezone of the completion prematurely.

In the experiment, adjustment of theflow into each of the valves was made onthe basis of observations of the frontmovement, using computer-assistedtomographic scans (Figure 3.19). Insubsurface reservoirs it will also benecessary to image the front movementin order to devise a control strategy.Research is underway to develop reliablesensors for this purpose.

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The experiment demonstrated thatproducing each zone at its optimal rateimproves the overall hydrocarbonrecovery from the well. When all threevalves in the wellbore were fully opened,only 75% of the ‘oil’ was displaced. Byjudiciously adjusting the three valves inthe experimental apparatus, sweepefficiency increased to 92%.

State-of-the-art monitoring and flow-control technology minimize the needfor well interventions and make thoseinterventions that are necessary morecost-effective by simplifying them ortiming them optimally. As demonstratedin the Wytch Farm and Troll fieldexamples, additional incrementalreserve recovery is more likely when theindividual zones or wellbores can beoperated independently, produced atprecise rates to avoid water or gasconing or excessive drawdown, andassisted by artificial lift systems.

Intelligent completions also affect theway people work.Designing these systems

involves closer interactions on a technicalbasis between operators, and service andequipment providers to ensure safer andmore effective completions. A remotelyoperated, intelligent completion mayreduce the number of people needed atthe wellsite, so field operations becomeless expensive and more people canremain in their offices.

Advanced completion technology is stillin its infancy and is currently most usefulin high-cost areas, but ultimately willenter other cost markets as thetechnology is simplified and proven inother theaters of operation. A futurechallenge will be to build intelligentcompletions equipment for casing of lessthan 7-in. in diameter. The combination ofexpertise in flow-control valves anddownhole electronics is crucial, and willdetermine the future development ofmonitoring and flow control systems. Thejoint efforts of reservoir specialists andcompletion experts will put downholeprocess control on the road to ubiquity.

180

180 180

No control

75%

27

Control

92%

Flow rate, cm3/hr

Injection, cm3/hr

49.5 103.5

Figure 3.19: Theoptimizationstrategyexperimentdemonstrated thatproducing eachzone at its optimalrate improves theoverall hydrocarbonrecovery from thewell

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1. Drill to total depth (TD), run the appropriate logging package, attach window section to casing, and locatethe appropriate depth

2. Orient the casing window section using gyro/MWD. Cement casing using standard techniques and a dual-tubing plug

3. Drill out the urethane-filled inner sleeve from the window section. The lower drain can be drilled, completedand isolated with a retrievablebridge plug (RBP)

4. Run the whipstock andmono-positioning tool assembly. Set it inlower internal orient (IO) profile belowpremilled window. Retrieve running tool

5. Drill the lateral to TD (no millingis necessary). Retrieve drilling assembly

6. Retrieve whipstock andmono-positioning tool to allowclean-up run

7. Run cement deflector and deflect into lateral, continue in hole to bottom

8. Liner tie-back set by snapping into premilled window, locking casing in place. Liner can now be cemented if needed

9. Release running tool from liner and liftinner string to bushing-in liner. Pumpcement through inner string into the liner

The Schlumberger RapidTieback* nonmilling multilateraldrilling and completion system can be used at a Level 3multilateral junction or upgraded to Level 4 and 5. The 95/8-in.Level 4 system is designed to provide drilling and driftworkover access for 7 in. through the upper lateral, whilemaintaining normal drift through the mother casing to thelower lateral. The upper lateral is mechanically connectedand cemented to the mother casing, and the junction providesa debris barrier, but is not intended to act as a hydraulic seal,due to the permeability of the cement.

The system incorporates a patented premilled windowsystem that eliminates the need to mill casing material to exitthe upper lateral. This removes the inherent risks with milling,and reduces the time required to exit the casing. The exitingsystem utilizes Schlumberger’s unique whipstock, andrunning/setting equipment, which are designed for ease ofinstallation and removal.

RapidTieBack

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10. Retrieve cementing string andliner-setting assembly

11. Wash down with wash-over shoe and latch cement deflector. Retrieve cement deflector and mono-positioning tool from wellbore

12. Cemented junction complete as Level 4 with no restrictions in main bore