SPE-171792-MS

First-Ever Level 4 Multilateral Well in North Kuwait SuccessfullyCompleted, Improves Oil Production

Meshal Al-Khaldy, Abhijit Dutta, Bijan Goswami, and Ali Al-Rashidi, KOC; Leonque Rondon, Mohamed Warraky,and Mohamed Samie, Halliburton

Copyright 2014, Society of Petroleum Engineers

This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 1013 November 2014.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contentsof the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflectany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the writtenconsent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations maynot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

Kuwait Oil Company (KOC) has recently drilled the first multilateral well in a North Kuwait field toimprove oil production in productive layers subjected to water coning problems by increasing reservoirexposure using Level 4 multilateral technology. The multilateral well targeted the same sand in differentdirections with two laterals. Both of the laterals were drilled using rotary steerable drilling systems toreduce drilling time. The drilling process used a full suite of logging while drilling (LWD) tools, includingazimuthal deep resistivity technologies, to ensure the well path is precisely geosteered within the reservoirboundaries and density/porosity tools in real-time, combined with specialized modeling software toposition the well in the best possible reservoir.

Level 4 multilateral technology was selected after performing an extensive geological assessment andstudying the challenges of exploiting oil in the target sand reservoir. The 12 1/4-in. main section was casedand cemented with 9 5/8-in. casing to the landing point; the 8 1/2-in. lateral-I was drilled and completedwith 5 1/2-in. inflow control devices (ICDs). The sidetrack was performed by cutting a window from aspecialized latch coupling in the 9 5/8-in. casing; the 8 1/2-in. section was drilled to the landing point, andthe 7-in. liner was run and fully cemented. The 6 1/8-in. lateral-II was drilled and completed with 4 1/2-in.ICDs.

The fully cemented and cased junction or bifurcation should help achieve greater well integrity andprevent fluid migration from the adjacent area, while the specialized latch coupling should help ensureeasy access to either of the laterals, as required. The ICD technology and swellable packers were selectedto delay water breakthrough from an active aquifer.

This publication describes the application of multilateral and geosteering technologies, and analyzesthe advantages and disadvantages of the first multilateral well drilled in North Kuwait that began with acampaign of higher order (Level 4) multilateral. The well is considered to be a pilot well to identify thefeasibility of using multilateral technology as a production model to help enhance oil recovery and reducedrilling costs in the field by replacing the cost of drilling new wells.

IntroductionThe concept of multilateral drilling has been proven in many areas globally including Kuwait in complexand stacked reservoirs. The benefits include reduction of the upper drilling phase costs of a new well,improvement to the oil recovery, and significantly advancing well to oil production days. The multilateraltechnology was also found to be beneficial for exploiting oil in the upper strata within the vicinity of thehorizontal leg that generally remains untapped. Nonavailability of suitable surface location amidst matureoil fields full of pipelines and installations was another driving force for selection of the technology.Drilling horizontal wells aggressively primarily using ICD completion techniques was prevalent in NorthKuwait fields. Although some multilateral wells had been drilled in other areas, the technology had yetto be adopted in North Kuwait fields. Following the successful ICD horizontal well campaign in NorthKuwait, KOC decided to implement multilateral drilling techniques in its northern fields to evaluate thefeasibility and added value of using this approach. The objectives of the well were initially identified asthe following:

Drill an 8 1/2-in. pilot hole to define the formation tops and locate the best depth to land the 121/4-in. section in the desired layer.

Drill the 12 1/4-in. build section to land into the lower channel of the desired layer. Drill the 8 1/2-in. lateral section from the 9 5/8-in. casing shoe and geosteer the well trajectoryinside the lower channel of the desired layer.

Complete the lateral with 5 1/2-in ICD and swellable packers. Cut a window in the 9 5/8-in casing and drill the 8 1/2-in second lateral buildup section from thetop of the whipstock and land the well inside the upper channel of the desired layer.

Drill the 6 1/8-in. second lateral section from the 7-in. liner shoe and geosteer the well trajectoryinside the lower channel of the desired layer.

Complete the lateral with 4 -in. ICD and swellable packers. Produce from both laterals simultaneously on electrical submersible pump (ESP).

Several criteria were identified and examined based on reservoir characteristics and pressure as well asthe type of intended completion to help ensure careful selection of the proper level and type of multilateraljunction installation.

Multilateral System SelectionDuring this phase, the primary objective was to compare all available multilateral technologies anddetermine which technology was the preferred system for this field in accordance with the features of thereservoir, targets, casing setting depths, presence of gas cap or water intrusion, active zones, and casingdesign used in the area.

The milled window technology with control of window geometry (Fig. 1) was selected, rather than theconventional milling window. When the window is open in the casing without control, a roll off effectoccurs that generates distortion in the windows, which is likely to create operational problems duringrunning of directional bottomhole assemblies (BHAs) or liners in the lateral. Negative side force candivert the mill away from the ramp of the whipstock, causing the mill to exit the casing prematurely. Thissituation leads to a foreshortened full gauge window, which can adversely affect subsequent drillingoperations when it becomes problematic to exit the casing aperture with a stiff BHA (Ponton et al. 2010).

After comparing the technological advancement of multilateral (TAML) levels and design criteria inaccordance with the specific geological features from the field, the TAML Level 4 was chosen. Thisdecision was based on the need to isolate active zones in the new lateral drilled from the window and avoidcommunication between the reservoir considered to produce and upper layers. The TAML Level 4 is

2 SPE-171792-MS

characterized by running a liner, which could be completely cemented or stage cemented with the uppersection being cemented blank liners and the lower section as slotted liners with exposition in the reservoir.

The future reentry capacity in the upper lateral during the producing life was evaluated and consideredduring the selection of multilateral system. The latch coupling (Fig. 2) could match this requirement byproviding a reliable control of depth and orientation when the multilateral tools were set in the latchcoupling profile during construction of the well. This device will enable the setting of workoverwhipstocks during future operations. It also facilitates easy retrieval of the drilling whipstock afterwashing it over, as required to gain access to the first lateral. The latch coupling provides a full gauge topass directional tools toward the lower section of main bore and drill the planned lateral in the reservoir.

Multilateral Well DesignThe subject multilateral well in North Kuwait was designed as a dual lateral oil producer; the target forthe lower lateral was the lower channel, and the target for the upper lateral leg was the upper channelof the target sand layer.

The trajectory was planned toward an azimuth of 360 and average 89.8 inclination for the lowerlateral (L0). The well path was expected to be clear of faults; however, reservoir thickening was expected

Figure 1Milled window technology with control of window geometry.

Figure 2Latch coupling.

SPE-171792-MS 3

toward the landing point. The buildup section of this leg was planned to be 10 ft true vertical depth (TVD)into the lower channel in the target formation; the plan was then to maintain the well path in the samechannel through active geosteering.

The upper lateral (L1) was planned to be drilled from the window, and was oriented to 18 azimuth andaverage 89 inclination. The landing point was planned to be 5 ft TVD below the top of the upper channelin target sand formation; the plan was to then continue the drilling inside the upper channel.

The intermediate sections of both laterals were planned to be completed with cemented casing, whileproducing sections of both laterals were planned to be completed with ICD and swellable packerassemblies.

Both laterals were planned to be produced simultaneously with ESPs placed in the tangent sectioninside 9 5/8-in casing at an inclination.

The planned drilling phases included the following:Drilling Lateral 0. The lower lateral L-0 was drilled to the plan with the drilling phases outlined

below:

Drill 22-in vertical hole section and run 18 5/8-in surface casing and cement to surface with spudmud.

Drill 16-in vertical hole and run 13 3/8-in intermediate casing and cement to surface withwater-based mud (WBM).

The gyro data of the vertical section was taken to properly tie up the bottomhole location tosurface. A pilot hole was drilled to determine the landing point of the L0 lateral. An 8 1/2-in pilothole was drilled instead of a 121/4-in hole because of the availability of a motorized rotarysteerable system (MRSS) in the 8 1/2-in. hole size at the time. The pilot hole was kicked off at 6,508 ft with a mud motor. Thereafter, the BHA was changed to MRSS along with the full suite ofLWD consisting of gamma ray, resistivity, density, and porosity tools. MRSS facilitated a fasterpenetration rate in the pilot hole that was built to an inclination of 64 at 8, 250 ft measured depth(MD) with a build rate of 4.5/100 ft. The tangent section was then drilled cutting across varioustime dependent problematic shale layers to 8, 993 ft MD (8, 252 ft TVD). An 8 1/2-in pilot holedid not need enlargement to 12 1/4 in, as it was plugged back for drilling the buildup section tothe landing point. A total of 19 pressure points were taken in the open hole through wireline forreservoir pressure evaluation. The pilot hole was drilled using 11-lbm/gal oil-based mud (OBM).

Results of the pilot hole at 64 inclination were used to replan the well for precise landing insidethe LC formation. An 8 1/2-in pilot hole was plugged back and the well was side tracked with a12 1/4-in bit at 6, 194 ft from the vertical section using a mud motor. The BHA was changed toa rotary steerable system (RSS) with measurement while drilling (MWD), gamma ray (GR), andresistivity tools with resistivity at bit for precise landing. The 12 1/4-in buildup section was drilledand landed precisely in the LC formation to a depth of 8, 855 ft MD (8, 055 ft TVD) at aninclination of 87.5, and an azimuth of 360 with dogleg severity (DLS) varying between 4.5 and6/100 ft. The L0 buildup section was drilled with 11.2-lbm/gal OBM. 9 5/8-in casing with latchcouplings connected at 7, 890 and 7, 813 ft were lowered and cemented to surface. The latchcoupling with one redundant was the main component for precise multilateral window cutting,orienting, and re-entry. It acts as an orienting seat for window cutting, whip stock, and subsequentre-entry tools.

Lower latch coupling orientation was confirmed with a key orienting tool and both latch couplingswere simultaneously cleaned.

Drill a 8 1/2-in lateral hole geosteering inside the LC of sand formation using density, porosity,GR, resistivity and distance to boundary tools from 8, 855 to 11, 000 ft MD (8061 ft TVD) with

4 SPE-171792-MS

inclination between 88 and 90, azimuth 359, and minimum DLS with a total lateral section of2, 145 ft. The L-0 lateral was drilled with nondamaging 8-lbm/gal OBM mud.

A stiff full gauge 8 1/2-in roller reamer run consisting of one near bit reamer and three stringreamers separated by a joint of 6 1/2-in drill collar was run.

A production screen test (PST) is an essential step to help ensure plugging free ICD performancewas carried out before deploying an ICD sand screen assembly. PST was conducted by passing300 mL of OBM at 10 psi in 2 secs through the sample screen of the actual sand screen deployed.

A 5 1/2-in ICD completion assembly consisting of 47 ICD with sand screens and 25 swellablepackers were lowered with 2 7/8-in inner string in tandem. The inner string stinged into the sealassembly of the outer string enables circulation in the outer annulus from bottom. The ICDassembly was deployed by setting a 7- 9 5/8-in. liner hanger with a liner top packer. The openhole interval was displaced first by filtered water followed by filter cake breaker fluid to eliminatenear-wellbore damage before setting the liner top packer. Selection of the number and placementof ICDs, swellable packers, and each ICD nozzle size is performed after reservoir simulation basedon accrued logging data. An ICD completion assembly is used to divide the lateral section intosegments by swellable packers and create custom made differential pressure across ICD nozzlesto delay the water cut.

The L-0 lateral was isolated with a retrievable bridge plug with sand dumped over it for laterretrieval.

Drilling Lateral 1. The upper lateral L-I was drilled to the plan with the drilling phases outlinedbelow:

The window was cut and a whipstock set in 9 5/8-in casing using multilateral technology describedlater. The 8 1/2-in window was cut from 7, 867 to 7, 877 ft in the tangent section having aninclination of 44.

The 8 1/2-in. built up section was drilled using RSS from 7, 877 to 9, 032 ft MD (8, 025 ft TVD)at an inclination of 87 and azimuth of 18 with DLS varying from 4.3 to 5.4/100 ft to the topof the upper channel of the sand formation using 11.4-lbm/gal OBM.

7-in Liner with ECP along with a transition joint at 7, 868 ft was lowered. The transition joint waslanded on the whipstock top at 7, 867 ft for setting the liner and cemented to top of the transitionjoint inside 9 5/8-in casing. The ECP was set at 7, 970 ft (90 ft below milled casing exit) to isolateany probable water zone at the casing exit.

Drill 6 1/8-in lateral hole geosteering inside the upper channel of the sand formation using density,porosity, GR, resistivity, and distance to boundary tool from 9, 032 to 10, 780 ft MD (8, 071 ftTVD) with inclination between 87.5 and 89.5, azimuth 19 to 21, with a total lateral section of1, 748 ft. The L-I lateral was drilled with nondamaging 8.1-lbm/gal OBM mud.

The 6 1/8-in Lateral section had to be side tracked once from the previous shoe after placing theside track cement plug, as the trajectory could not be maintained by the desired zone and landedinto the transition zone, leading to wellbore instability issues.

A stiff full gauge 6 1/8-in roller reamer run consisting of one near bit reamer and three stringreamers separated by a joint of 4 3/4-in. drill collar was run. PST was successfully conducted.

4 1/2-in ICD completion assembly consisting of 32 ICD with sand screens and 20 swellablepackers were lowered with 2 7/8-in inner string on 5- 7 in. retrievable hydraulic sealbore hanger.Filter cake breaker fluid was placed in the open hole as before.

It was estimated that formation top depths could change during the operation phase because of theinformation collected from the pilot well and geosteering software.

SPE-171792-MS 5

Multilateral OperationsThis section describes runs made to create the multilateral, including the latch coupling, latch cleaning,milling machine, drilling whipstock, and 7-in. liner runs, and the whipstock retrieval.

Latch Coupling Run

The latch coupling was run with the 9 5/8-in. casing. A second latch coupling was run as a contingency.The latch coupling depth had to be analyzed during the planning and implementation phase to properlylocate it in order be able to perform all multilateral operations. This depth also had to coincide with thearea where the upper lateral was planned.

The float shoe, shoe track, and a float collar were picked up and run in the hole. The float equipmentwas tested. 9 5/8-in. 43.5-lb liner was picked up and run in the hole before the primary latch coupling wastorqued up, followed by the second (contingency) latch coupling. A total of 229 joints of 9 5/8-in. casingwere run in the hole to the target depth of 8, 851 ft. The primary latch coupling depth, as per the casingtally, was 7, 889 ft. The cement job was performed with Latex 2000 additive.

Latch Cleaning RunFunctions of the latch cleaning tool (LCT) include testing the latch coupling profile and cleaning out anydebris inside the latch coupling; it is run with a MWD tool to detect the latch coupling orientation. Theoffset between the LTC and the MWD tool must be considered a critical activity; its measure must bereviewed by all the parties involved in this operation.

The LCT was picked up and made up with the MWD tool. The offset was measured from MWD tothe key of the LCT. The BHA was tested at surface. The BHA was run in the hole to the latch couplingdepth. When the BHA reached the primary latch coupling depth at 7, 889 ft, it began to circulate to cleanby jetting the latch coupling profile. The LCT was latched and weight was slacked off to ensure positivelatching. The string was picked up to neutral, and the pipe was marked for depth and orientation. TheMWD toolface reading and orientation of the lower latch was confirmed. The LCT was unlatched withthe required overpull, and the latching process was repeated to confirm the same toolface orientationreadings.

Milling Machine RunThe use of a milling machine can help create a symmetrical window because it can control the millingprocess and help prevent the roll off effect (natural tendency of turning right). It is considered to be animportant tool to create a Level 4 or 5 system because it will avoid any obstruction to the running of theliners inside the upper lateral; it is run before running the drilling whipstock.

The milling machine was picked up and made up to the BHA that was designed for maximum debrisrecovery. Its pistons were tested at surface. The milling machine was run in the hole until it reached the

Figure 3Whipstock with mill assembly.

6 SPE-171792-MS

latch coupling depth at 7, 889 ft. The tool was set in the latch coupling profile with the whip face orientedat high side. Circulation was started to begin milling the window. The window was milled to full lengthwith controlled parameters. An additional clean out assembly was run to retrieve metallic junks generatedbefore deploying the whip stock.

Drilling Whipstock RunThe drilling whipstock can create a full gauge window to access the lateral and, at the same time, thewindow mill and watermelon mill are run with the whipstock connected with a shear bolt (Fig. 3). Afterthe whipstock is set and confirmed with weight, the bolt is sheared, and a rathole is drilled to pass thedirectional BHA without restriction through the window area in future operations.

The latch keys, which are located in the lower part of the whipstock, enable the setting and orientingof this tool in the matching key slots of the latch coupling at 7, 890 ft. In the field, the assembly wasrotated and slowly lowered into the latch coupling. This rotation stops when the latch keys match with thelatch coupling profile, providing the whipstock the capacity to support weight and torque. The applicationof slackoff weight is needed to shear the bolt. The window was open up over its full length with 8 1/2-in.full gauge milling assembly, and the rathole was drilled. The mills were worked out through window andrathole several times without any drag or overpull. Sweeps were pumped for additional clean up.

7-in. Liner RunIn multilateral wells, liner through the junction is not set using the traditional liner hanger. A transitionjoint is used instead. After the upper lateral was drilled, the 7-in. liner was run to isolate active zones andto continue the drilling of the 6 1/8-in. section. During the operation, all liner string was run accordingto the well program. The transition joint was connected with the last liner joint and was run with a runningtool on drill pipe. The transition joint is placed above the liner running tool that is connected to linerrelease mechanism, liner pack off bushing and liner wiper plug. It is mainly used to provide a smoothaccess to the lateral and is located through the whipstock face. The transition joint was landed on thewhipstock top for setting the liner. The landing was confirmed several times by slacking off weight. Theliner was cemented to top of the transition joint inside 9 5/8-in casing. The liner running tool was releasedand pulled out leaving the cemented transition joint in place just inside 9 5/8-in casing. During thewhipstock retrieving process, part of this transition joint was cut and recovered.

Whipstock Retrieval with Washover PipeThe washover pipe is a tool that enables the retrieval of the whipstock by milling out its centralizers; atthe same time, it can cut part of the transition joint and remove the excess cement around the whipstock(Fig. 4). It is considered to be the primary tool for retrieving a whipstock during the implementation ofLevel 4 well.

In the field, the washover BHA was run in the hole. After the BHA was above the top of the whipstock,the parameters were recorded without pumps and with different pump rates. Top of whipstock was taggedand pipe was marked accordingly. The interval across the whipstock was washed and milled as per themilling parameters. On completion of the washover process, weight was applied to activate grapple andthe whipstock was engaged. The whipstock and washpipe were then pulled out of the hole.

Figure 4Washover process to retrieve a whipstock.

SPE-171792-MS 7

GeosteeringThis section describes the geosteering plan, real-time operation, and well maneuvering steps taken tomaximize drainage length through sweet spots.

PremodelingGeosteering technologies were used to assist in picking the 9 5/8-in. casing point and in locating thelanding point to 10.0 ft TVD below the top of the target lower formation channel. Another objective wasto assist with picking the 7-in. casing point in the upper lateral and the landing point, up to 5 ft TVD belowthe top of the target upper formation channel. After the liner was set in the upper lateral (L1), thegeosteering software helped drill the upper lateral within the desired upper channel.

To model the reservoir, three offset wells were used for the analysis. For prewell modeling purposes,the pilot hole of the subject well, Offset-1 Offset-2, and Offset-3 wells were used (Fig. 5). The historicalwireline log data was provided. The offset wireline data with the grid surfaces were used to construct theinitial models to predict the LWD log responses through the desired lateral section.

All information provided in the beginning helped to create an initial model with the original directionaldrilling proposal plotted against the geology. The proposal included landing the well in the target lowerformation and drilling a horizontal path through the target lower sand formation (Fig. 6). The lateral had

Figure 53D map of the well.

Figure 6Original prewell model for ML-L0.

8 SPE-171792-MS

the heel at 8, 929 ft MD/8, 065 ft TVD, and the total depth (toe) at 11, 270 ft MD/8, 081 ft TVD, accordingto well plan (Fig. 7).

Real-Time Operations (12 1/4-in. Hole Build Section and Main Bore Lateral)The real-time operation began from 7, 300 ft MD in the 12 1/4-in. hole section in accordance with the wellplan. The primary objective of using the geosteering software was to help select the 9 5/8-in.casing point.The hole was drilled with a RSS with GR at the bit, GR, and resistivity LWD tools. The offset wells wereused as the primary offset wells for the initial correlation, and the well plan was followed to drill thedeviated hole section. Several stratigraphic modifications (small changes in TVD with respect to the actualgeology) were necessary to correlate the real-time GR. During the operations, the geosteering real-timeoperations helped select reference formation tops 6 ft TVD shallower compared to the pilot hole.

The drilling operation continued smoothly through different formations. The W-sand formation waspicked 11 ft TVD shallower than the pilot hole because of increased formation thickness. As a result, thetop of the M-limestone formation was picked 5 ft TVD shallower than the pilot hole. The apparentformation dip was dipping up slightly. The continued to be 4 ft TVD above the planned trajectory inthe well plan. As the trajectory continued, it became closer to the Offset-3 well and farther from the MLT

Figure 8Landing point 4 ft TVD into the target lower formation.

Figure 7Final MLT well compass view.

SPE-171792-MS 9

pilot hole. This meant it was possible that the thickness of the target upper formation would be5 ft TVDthicker approaching the landing point. The target upper formation was 6 ft TVD thicker, as expected, thanthat observed in the pilot hole because of the closer proximity of the trajectory to the Offset-3 well. Fig.8 show the 9 5/8-in. casing point/landing point (the same point) and that the trajectory was placed 4 ftTVD into the target lower formation in accordance with geology requirements.

The 9 5/8-in. casing point was reached at 8, 855ft MD/8, 054 ft TVD/inclination 87.5 (as perdirectional driller (DD) projection), (Fig. 9). The 9 5/8-in. casing point was 4.0 ft TVD into the targetLower B-formation as planned, and the trajectory was 15 ft TVD above the landing point in the well plan.The 9 5/8-in. casing was run successfully to bottom, including two latch couplings at the desired depthsfor junction orientation later, before drilling the upper lateral.

The main 8.5-in. Lateral-0 was geosteered inside the target lower formation using density, porosity,GR, resistivity, and distance to boundary tools from 8, 855 ft to 11, 000 ft MD (8, 061 ft TVD) withinclination between 88 and 90, azimuth 359, and minimum DLS with a total lateral section of 2, 145ft.

Upper Lateral: 8 1/2-in. Build SectionThe primary objective for geosteering was to help pick the 7-in. casing point 3 to 4 ft TVD within thetarget upper formation. The L1 began within the upper M- formation, and the well plan was followed todrill the L1 build section. The hole was drilled with RSS in combination with GR, resistivity, near bitgamma, and at bit resistivity LWD tools. The offset wells, Offset-3, Offset-2, and MLT pilot were usedas the primary offset wells for initial correlation. The correlation continued to be very good with both GRand resistivity through the M-formation (Fig. 9) and into the target upper formation (Fig. 10).

The expected 7-in. casing point was going to be lower than that predicted in the well plan because ofthickness variations in the expected formations sequence. As drilling continued through the upper layerof target formation, it was clear that the thickness of the boundary between this zone and the target upperformation channel was thicker than the original MLT L0 leg.

MLT L1 reached the casing point, in accordance with requirements, at 4 to 5 ft TVD into the targetupper formation channel in the clean low GR zone. The formation dip was interpreted to be locally 2.5to 3, dipping downward at the casing/landing point.

The total depth of the section was reached at 9, 032 ft MD/8, 024 ft TVD/87.3 inclination and 18azimuth, 11 ft TVD below than the original well plan.

Figure 9Top of the target formation.

10 SPE-171792-MS

Upper 6 1/8-in. LateralThe RSS assembly was used to drill the lateral with At-Bit resistivity and GR, azimuthal litho density,azimuthal deep resistivity, and compensated thermo neutron LWD tools. Drilling continued according toplan, but difficulties with building angle related to formation characteristics that had high drilling ratewere experienced. Despite all efforts, the well path continued dropping below the plan, which wascontrolled and angle buildup reached 89.5.

This was less than the up resistivity, and an attempt was made to maintain 89.5 to remain in midtarget, or gain slightly in TVD. This strategy appeared to be working as the up/down resistivity cametogether and the geosignals were at 0 at 9, 720 ft, indicating mid target. However, at 9, 790 ft, these valuesagain very quickly began to diverge, and by 9, 820 ft, the decision was made to drop to 89. By 9, 850ft, the down resistivity was beginning to polarize, indicating very close proximity to a bed boundaryabove. The well necessitated dropping angle as quickly as possible to 88.

The well path appeared to end very near the top because the geosignals were positive, the downresistivity polarized, and the GR increased slightly to just above 20 API. The inclination was dropped to88, and the formation appeared to flatten slightly to 1.5 down dip; consequently, the exit from the topwas avoided. After successfully retreating from the roof, the geosignals began decreasing, then quicklyincreasing. Some sort of faulting was suspected for causing the rapid change because other interpretationswould have involved severe dip changes. After the GR began increasing, it was apparent that the bit washeading out the top. Because of the amount in TVD that had already been decreased in this well, it wasdecided to call TD at 10, 779 ft. Fig. 10 shows the final cross section.

Figure 10MLT well final cross section.

SPE-171792-MS 11

CompletionUpon successful drilling of the L-0 and L-1 laterals and successfully deploying 5 1/2-in and 4 1/2-in ICDassemblies respectively, retrieval of the whipstock assembly and a cleanout trip was made to removedebris and sand on top of the retrievable bridge plug (RBP). Subsequently, the RBP was retrieved.

The ESP assembly was run on 3 1/2-in. tubing. The well was flowed substantially so as to have oilaround the swellable packers in the horizontal sections to allow swelling the packers uniformly. Thehorizontal wellbore if not covered with oil fully might leave a communication gap on the low side of thewell as water shall accumulate on the low side, thereby hampering the expansion process. The well waslater put on production on ESP with very encouraging results.

ConclusionsLevel 4 multilateral installations, although prevalent worldwide, requires significant planning and prep-aration efforts With careful planning and implementation, the subject well was completed relativelysmoothly and within the stipulated authority for expenditures (AFE). This was not only the first Level 4multilateral well, but the first ever multilateral well of any type in North Kuwait. Drilling the Level 4multilateral well on the first attempt and achieving phenomenal success is praiseworthy. The achievementwas possible because of the consorted and combined efforts during planning and execution of allstakeholders involved. The success of the Level 4 multilateral well and the encouraging flow testingresults could be a game changer in the field development process in North Kuwait fields.

ReferencesPonton, C.B., Robert, J.M., Fipke, S.R. et alet al. 2010. Are You on the Right Track With Casing

Milling? Innovative Precision-Milled Windows Offer Improved Casing Exit Reliability for Sidetrackingand Multilateral Completions. Presented at the IADC/SPE Drilling Conference and Exhibition, NewOrleans, Louisiana, USA, 24 February. SPE-127764-MS. http://dx.doi.org/10.2118/127764-MS.

12 SPE-171792-MS

First-Ever Level 4 Multilateral Well in North Kuwait Successfully Completed, Improves Oil Produc ...IntroductionMultilateral System SelectionMultilateral Well DesignMultilateral OperationsLatch Coupling RunLatch Cleaning RunMilling Machine RunDrilling Whipstock Run7-in. Liner RunWhipstock Retrieval with Washover Pipe

GeosteeringPremodelingReal-Time Operations (12 1/4-in. Hole Build Section and Main Bore Lateral)Upper Lateral: 8 1/2-in. Build SectionUpper 6 1/8-in. Lateral

CompletionConclusions

References