00035668 planning the first horizontal well in elk hills.pdf

8/19/2019 00035668 Planning the first horizontal well in Elk Hills.pdf

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SPE 35668

Planning the First Horizontal Well for the Shallow Oil Zone of Elk Hills Field, KernCounty, California

LT James Hardin, CEC, USN, SPE, Department of Energy, Jim Martin, SPE, Bechtel Petroleum, Joe Davidson,Bechtel Petroleum, and Martin Paulk, SPE, Baker Hughes INTEQ

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Abstract

A horizontal well was successfidly drilled and completed inthe Shallow Oil Zone (S02) of the Elk Hills field (NavalPetroleum Reserve l), Kern Co., California. The reservoirformation is Pliocene age, low pressured, unconsolidatedsands separated by thin, impermeable shales. The well wasdrilled to a TVD of 3,998 feet and an MD of 5,648 feet, A1,111 fl lateral was drilled at 90° and 580 ft of that wascompleted in two sands. Adjacent wet sands, faults and a thinpay zone were some of the chaJ1enges faced in planning anddrilling this well.

This paper addresses the reservoir characteristics of thepay zone, plaming of the well, and drilling and completionmethods that were used. Results of drilling operations,completion operations, production performance and costs areprovided, and some comparisons are made to offset verticalwells,

Introduction

Horizontal drilling has proven itself in recent history as ahighly profitable alternative to conventioml vertical drilling,

In a paradigm shift, horizontal wells have become common insome applications, displacing vertical wells.

The Shallow Oil Zone at the Elk Hills field was originallydeveloped through vertical drilling as a strategic reserve underthe management of the Department of the Navy (now underthe U.S. Department of Energy). Of the estimated 1.6 billionbarrels of oil in place in the SOZ, approximately 450 millionbarrels have been produced since the early 1900s, The SS- 1(Sub Scalez One) is the most significant oil producing sandwithin the interval referred to at Elk Hills as the S02. Gravitydrainage and low reservoir pressure in the SS-1 sand have led

to a low reservoir decline rate and long productive well lives.This is especially true along the southern flank of theanticlinal structure which comprises the primary trap for oiland gas in the SS-1 sand. Realizing this, recent planning forthe S02 has focused on accelerating recovery and increasingrecoverable reserves.

The SS- 1 sand at Elk Hills has reservoir characteristicssimilar to other reservoirs that have been exploitedsuccessfidly by horizontal well technology. Initial evaluationsuggested that horizontal wells could economically accelerateand increase recovered reserves if several challengingobstacles could be overcome.

Resewoir Characteristics

The SS-1 is a member of the Pliocene San Joaquin Formationand has been divided into twelve sublayers within the easternportion of the field.

These sublayers are separated by thin shales which serveas vertical seals through most of the productive area. Gas/oiland oil/water contacts vary between sublayers. Individualsublayers vary considerably in thickness across the field andpinch out locally, and to the west entirely, along trends easilydefined by well logs.

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2 Planning the First Horizontal Well for the Shallow Oil Zone at Elk Hills Field SPE 35668

The location chosen for a horizontal well in the SOZ wasthe south flank of the highly faulted eastern anticline whichcomprises the major trap for oil in the SOZ, The SS- 1 in thisarea has an average dip of 30° to the south-southeast and

strikes N 80° E, In this vicinity. the SS-1 is composed ofseven sublayers with fluid contacts which vary between faultblocks as shown in Fig 1. Sublayers Q, P, PA, and AU are oilbearing, and sublayers A, Al and B are wet in this location.

Vertical logs of wells at both ends of the horizontal well27H-11 G indicate that the SS-1 produces from four subsandsat the eastern end of the well (Figs 1 and 2). Two productivesublayers at the west end are sandwiched between waterbearing subsands, A structural map of the area surroundingthe horizontal well is shown in Fig 3.

Significant faulting, water in close proximity to theproductive sands, and a thin productive interval indicated thatprecision directional control would be required while drillinghorizontally. Water isolation is required because of the highrisk of penetrating the water bearing sublayers.

Drilling Planning

A horizontal program in the SOZ had to create a morefavorable economic position comprised of significant oilacceleration andor higher oil recovery compared to thevertical well program if it was to be pursued. Horizontal wellsin situations similar to the SOZ have been shown in theoryultimately to recover 20 to 30 percent more oil and haveinitial production (1P) rates of 2 to 3 times those of vertical

wells based on ten acre spacing’,In a horizontal well producing under 1,500 bbl/day and oilgravity above 20 API, the pressure drop along the lateral canbe neglected. Therefore, the rate and reserves of ahorizontal well in a low pressure, gravity drainage reservoirare strongly dependent upon the length of the lateral.Reatizing this, the horizontal well in the SS-1 was planned tocross and drain two ten-acre locations. This was perceived tobe the best balance between the rate, reserves and drilling risk.

Prior to spudding the horizontal well, directioml gyrosurveys were run in thrm offset wells which were heretoforeshown as vertical because no surveys were available for thesewells. Lateral drift in an up-dip direction was suspected in

these wells based on the results of surveys taken in other offsetwells in the area. Results of the three new directional suweysplaced the wellbore intercept locations at the top of the SS-1,north-northwest from their surface locations, This distanceranged from 79 ft in welI 86-IOG to 193 l in well 77-1oG Fig 3). Re-mapping the structure based on the correctedlocations for the top of the SS-1 in these wells resulted in asignificant northerly shift in the mapped structural contours.Had these surveys not been run, the mapped structure wouldhave been off strike in this area and the planned horizontalwell path would likely have missed the target pay sands.

The chosenpath for horizontal well 27H-I lG was positionedbetween two wells producing from the SS-1. Well 27-1 lG islocated on the eastern end of the proposed well path and well77A-1OG is located on the western end. These two wells are on

strike with one another, yet the well on the east is completed inthe four uppermost sublayem in the SS-1, all of which contain oil,and the well on the west is completed in only the lower two ofthese same sublayers. The uppermost two sublayers are present,but we~ in the western well, The remaining three lowermostsublayers of the seven SS-1 .subIayersfound in this area are wet inboth wells.

It was assumed that an unmapped fautt most likely exists atsome unknown location between the two flanking wells. This faultwas responsible for creating a barrier and thus a change instructural elevation for oillwater contacts across the fault in atleast two of the sublayers present in both wells.

With the knowledge that a fault would likely be encounteredsomewhere along the horizontal well pati it was surmised thatatler crossing this fault the remainder of the well woutd probablybe wet in at least two sublayers, thus mirroring the pay section inthe 77A-1OG well.

The majority of the faults along the south flank of the structureare down thrown to the east. Therefore, drilling horn east to westlikely would resutt in the well passing from the down-thrownblock into the up-thrown block. If the throw along this fault weregreater than the thickness of the oil column in this ar~ a wetsublayer located below the oil sands would k encounter~ but ifthe throw along this fautt was less than the oil column, the wellpath could remain in the oil sand even tier crossing the fault. Ifthe SS-1 sands were encountered structurally lower, rifler crossinga fault with the reverse sense of throw than was expected, then thepenetmted sand could be wet in this position as well.

The well was designed to be drilled from east to we~ trendingslightly sub-pamllel to strike, as mapped absent the fault. Thelateral section would be at about the same structural position forthe SS-1 as the two end wells. Along its horizontal pafi the wellwould be steered so that it would encounter three of the foursublayers productive in the eastern well, starting in the deepestproductive sand. At midpoint the well would be turned back intothe structure, thus encountering tire same three sublayers inreverse order.

The horizontal well profile was designed with a medium

radius build to the tangent section. A three-dimensional viewof the initial directional plan is shown in Flg 4.

The first horizontal target was set at 200 ft west on strikefrom the vertical well 27-1 IG. The advantages of this firsthorizontal target were that the existing well, 27-11 G, could beused as a pilot hole. Formation evaluatiordmeasurementwhile drilling (FE/MWD) measurements could be modeledfrom the logs of 27-11 G to help in placing the lateral in thethin productive interval. Geologic uncertainty could also beminimized for the 9 5/8” casing point, a critical factor in thesuccess or failure of the well.

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SPE 35668 JAMES HARDIN, JIMMARTIN, OE DAVIDSON, MARTINPAULK 3

The 9 5/8” casing was set in the lowermost productivesand because:

1) Experience in the area indicated that lost circulation

could occur anywhere in the SS- 1, and when it did occurthe upper hole would always fall in, sticking the drillstring. Risk of losing the FE/MWD tools necessitatedsetting the 9 5/8 casing in the SS-1 prior to drilling thelateral.

2) The productive sands would be drilled in the buildsection and FE/MWD measurements could be used toretinethe initial model obtained from we1127-ll G.

3) It was known that the Above Scalez (AS) sand, ahigh-pressure water sand, would be penetrated prior toreaching the productive interval. It was critical to placean ECP and stage collar between the high pressure ASand the low pressure productive SS- 1 interval.

4) If the first horizontal planned target was in error andthe water sands were penetrated, the course directioncould be changed to enter the productive sands again.The water-bearing sands would be isolated by the 9 5/8”cemented casing.

Sublayers of the SS-1 are relatively thin but areallyextensive. Communication across sublayer boundaries isthought to be minimal. Therefore, it was believed drillingthrough each productive sublayer was critical for drainage tooccur in all productive sublayers.

Taking into consideration dogleg severity limitations inthe lateral section, a 1,200 ft lateral was planned. It wouldenter each productive sublayer twice by initially drilling out ofthe structure, starting at the lowermost productive sublayerdirected initially at approximately 8“ azimuthal strike out ofthe structure. While drilling at approximately the center ofthe lateral, a course change relative to strike would put thecourse direction into the structure so that the well would drillfrom the uppermost to the lowermost productive layer,

Since the first half of the lateral was expected to be a‘inirror image” of the second half of the well, the logs fromthe first hatf of the lateral were to be used as a road map forthe second half. This minimized the risk of penetrating the

water at the end of the well.Completion. The lateral would be completed with one of twopossible scenarios, depending on what was encounteredduring the lateral drilling phase. The preferred completionwould be a 7“ slotted liner throughout the lateral section. Acemented 7“ liner would be used if water were encounteredwhile drilling the lateral section. Incremental cost for acemented verses slotted liner would be approximately$100,000 due to tubing-conveyed perforating. Shot holes for aperforated liner would increase the risk of sanding problems,However, having the 7“ cemented liner would allow runningan inner liner if needed.

The majority of all recent vertical wells in the SS- 1 havebeen completed with a perforated cemented liner. As sandproduction is highly dependent upon water production in theSS- 1. vertical wells similar to 27-11 G typically produce sandinitially but clean up with time.

Formation pressure of approximately 160 psi and sandproduction limit options related to artificial lift. The initialartificial lift design for the 27 H- 11G was to be a rod pumpwith rod guides. The pump would be set at the top of thesecond build section in the tangent (Fig 5).

Prewell Modeling. The low resistivity contrasts, thin layersand moderate dip angle in the SS- I sand sequence presented avery challenging reservoir in which to navigate a horizontalwell. The lateral discontinuity of the four subsands named Q,P, PA, and AU sublayers suggested from comparison of the27-1 lG and the 77A- 10G that offset logs would firrthercomplicate this task Figs. 1 and 2).

Phasor processed induction logs from the 27-11 G wellwere used as the starting point for initial predictive resistivitymodeling. Separation features and polarization horns at thebed boundaries of each of the four productive layers were theprimary log responses that would be used to navigate the SS-1. The model suggested that the deepest depth ofinvestigation resistivity (400 kHz attenuation) and theshallowest investigation resistivity (2 mHz phase difference)would provide the earliest look-ahead capability and would betransmitted in real-time along with the near bit inclination(NBI) and a single oriented gamma ray.

The resistivity model was then integrated with thestructure model and proposed well plan to generate anexpected resistivity response versus measured depth Fig. 6)across the geological section, Track one of the plot includesthe spontaneous potential and gamma ray traces from the 27-11G offset well stretched over this geologic cross section, Atrue vertical depth trace is also plotted across the results of thestructure model in track one to represent the theoreticalstrati graphic positioning of the wellbore. Track two includesthe phasor processed induction log, which also is stretchedover the proposed well path. Track three shows the fourmodel resistivity traces and the annotations of the proposedinclination and azimuth. The dip angle and direction derivedfrom a structure map of the top of the AU sublayer areannotated vertically in the depth track. Several well planscenarios were modeled to optimize the productive intewal inthe P, PA, and AU sublayers.

This interactive computer model would be utilized at thewell site to account for deviations in the directional well planor stratigraphic position, enabling a direct real-timecorrelation of synthetic model resistivities and FE/MWDmeasurements.

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SPE 35668 JAMES HARDIN, JIM MARTIN, JOE DAVIDSON, MARTIN PAULK 5

The correction in dip direction to the south, combined withthe 4.0° azimuth turn to the south prior to casing point.resulted in an 8.5° change in the angle of incidence between

the wellbore and the SS- 1 sands. With this input, thenavigation model projected that the planned wellbore wouldapproach the top of the AU at 4,700 feet IUD and then exit thebottom of the AU at approximately 5,225 feet IvfD.

Fig. 8 models the TST-converted build intervalresistivities in track 3. Actual resistivities are shown in track2. The updated structure model, stretched wirelinespontaneous potential and both model and actual gamma raysare shown in track 1. This log shows that the prominentresistivity anomaly from 4,340 to 4.398 feet MD correlateswell with the navigation model. However. this assumes thatthe dip direction deltas from the prewell structure map.equating to over 11.00 of additional dip direction to the south,were accurate. The structure changes through the buildinterval and the proximity of the 77A- 10G well to theproposed bottom hole location indicated that this was notpossible. The new dip direction projected across the entirelateral section more closely corroborated the 77A-1OG data.

Using the navigation model, a new well plan wascalculated to optimize productive intewals in the AU, PA andP sublayers. This plan called for an immediate 2.0” turn tothe south to avoid re-exiting the bottom of the AU. At thispoint, the well bore would be navigated through each of thezones with the intention of turning back to the north towardsthe 77A- 10G well. Projecting the new plan against the

previous plan to the center of the lateral resulted in a mid-point position 70 feet south of the original plan.

Drilling the Lateral. Class H bIowout prevention equipmentwas nippled up on the 9 5/8” casing head, and the 9518” stagecollar and the cement and float shoe were drilled out whilechanging-over the mud system to a 65 pcf low solids non-dispersed fresh water drilling fluid.

Upon drilling out of the 9 5/8” casing, resistivityseparations correlated well with the bottom of the AU. Fig. 9illustrates the actual resistivity log in track 2, the new modelresistivity in track 3 and both the actual and model gammatraces in track 1. The TVD trace, wireline spontaneous

potential, rate of penetration, and structure model are alsoshown in track 1. Survey inclination and azimuth areannotated in track 3. Heavy bars on the outside edges oftracks I and 3 indicate intetvals where FE/MWD data wereacquired while sliding,

PE/MWD resistivity separations closely correlate with themodel through the major AU subIayer from 4,670 to 4,715feet MD. A good correlation is also shown between the modeland FEM4WD gamma ray readings. FE/MWI) resistivitiescontinued to increase as the bottom of the PA was entered at4,765 feet MD. The polarization horn seen at this boundaryand the increased resistivities in this lobe are indicative of alow angle of incidence. The apparent lengthening of the PA

from 4,765 to 4,955 feet MD indicated that the wellboredirection was very close to formation strike at this point,which would agree with this interpretation. A correction was

made to the structure model at 4,800 feet MD to adjust the dipdirection to the required 168.00.At approximately 4,900 feet MD, the 400 kHz attenuation

resistivity began to decrease dramatically, signifying theapproach of a less resistive zone, At 4,940 feet h4D, asignificant polarization horn resulted, which confhmed acontrasting resistivity bed boundary. Initially, this wasthought to be the shale break between the PA and P sublayers.Plans had been to navigate into the middle of the P and theninitiate a north turn back into the structure, headed towardsthe 77A- 10G well, Resistivities continued to decrease and thenavigation model indicated that the wellbore would exit thetop unless a correction were made. At 4.980 feet MD, theassembly was oriented to the right to initiate an azimuthcorrection. However, only two degrees of turn had been made(to an azimuth of 256.7°) by 5,088 feet IWD with nosignificantly increased resistivities. A trip was made at thisdepth to adjust the motor bend for a more aggressive turn rateand to get the well bore back into the PA.

Azimuth was turned to the right on the next run, with allresistivities increasing dramatically as the top of the PA wasentered again, Resistivity separations correlated well with themodel while quantitatively agreeing with resistivities in theprevious horizontal section of the PA. Gamma ray valuesthrough this interval also show good correlation with the

model. Now that the well bore was back into the PA, a slightturn back to the left was needed to avoid exiting it too quickly.No rotating was possible with this assembly due to bendinglimitations, so the assembly was pulled again to adjust themotor to a steerable mode. The last transmitted suwey forthis assembly showed a 263,4° azimuth.

Once the directional sensor was past the slide from theprevious run, the azimuth was 267.0°. Several slides weremade to obtain the 263.6° azimuth required to aim the well atthe 77A- 10G known point. PA appeared to be lengthening inthis section, indicating that the borehole was very close to theformation strike. A correction was made again to the

navigation model to adjust the dip direction to 177.0° at 5,200feet h4D. Close correlation with both the model resistivityseparations and the model gamma ray confirmed this,

Throughout this interval, the assembly began to buildangle. Attempts at sliding to correct the well path becameincreasingly dit%cult. An initial drop in resistivity at 5,385feet MD and the subsequent polarization horn contlrmed theexit of the PA at 5,380 feet MD, This bed boundary was notpredicted by the model to occur at this depth. Iterativechanges to the model to account for this resulted in anotherchange in the dip direction to 170.5” at 5,300 feet IvID.

The top of the AU was then entered at 5,428 feet MD,earlier than expected by the model, Another change to a dip

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6 Planning the Fimt Horizontal Well for the Shallow Oil Zone at Etk Hills Field SPE 35668

direction of 163.5° at 5,400 feet MD was necessmy to accountfor this. At 5,442 feet. a slide was initiated to dropinclination as the assembly continued to build angle. Thehigh resistivity upper lobe of the AU was then exited at 5,477

feet MD. The 400 kHz attenuation resistivity immediatelybegan to decrease dramatically, signaling the proximity of amuch lower resistivity bed. The lower lobe of the AU wasexited at 5,545 feet MD where all of the resistivities began todecrease rapidly. The assembly was oriented to the high sideof the hole in an attempt to avoid the approaching bed.However, the resistivities continued to decrease until reachingless than 2.0 ohm-m, where drilling ceased at 5,648 feet MD.

Cementing the Liner

It was originally planned to set a 7“ slotted liner in the 8 1/2”

hole. The FE/MWD tools indicated a potential wet interval inthe middle section of the lateral required isolation. Sincethere was no history of horizontal production and verticalwells in the SS-1 had the potential for sand production, it wasdecided to run 7“ casing so that a 4 1/2” slotted liner could berun inside the casing if sand became a problem. Because ofthis and the desire to isolate the potential water interval, a 7“solid liner was run and cemented in place in the 8 1/2” lateralhole. This had not been tried at Elk Hills, as there was somerisk in running the 7“ liner in the small hole.

An option that was considered but discounted was tounder-ream the lateral section and then run the 7-inch pipe.Experience with horizontal wells in other reservoirs at Elk

Hills dictated that the liner had to be properly centralized androtated for a successful cement job. Under-reaming the holewould cause the pipe to be decentralized unless bow-springcentralizers were used, and rotation would be difficult withbow-spring centralizers. It was believed that if the hole wereunder-reamed, the pipe would lay on the low side of the holeeven when centralized, and the cement would channel acrossthe top of the pipe, not displacing the mud on the low side ofthe pipe, causing a poor cement job. For this reason, the 7“liner was run using solid centralizers (2/joint) and rotatedwhile cementing,

To help reduce friction, the 7“ liner was run dry. The 7“liner was successfidly run to within 4 feet of TD and cementedusing 460 cubic feet of Class G cement with 1,75 gps of latex,0.1 gps stabilizer, 0.05 gps defoamer, and 0.5% dispersant.Attempts to rotate the liner were unsuccessful until the last 25bbl of displacement. The cement was preceded by 56 bbl ofchemical wash and 280 bbl of water to clean mud out of thehole. The cement was mixed and pumped at 8 barrels perminute so that the pre-flush fluids were in turbulent flow at alltimes while in open hole. Circulation was 100% during thecementing operation.

During the completion phase, a positive pressure test onthe liner lap after drilling out the cement indicated the lap was

cemented adequately, and a cement bond log contirmed thatisolation of the potentially wet zone was achieved.

Performance

After reviewing the drilling and completion activities, it wasdecided that the well would be perforated and tested in twostages, The two-stage approach was expected to providereservoir management information for t%ture prospects. Also,since it was apparent that several low resistivity intervals hadbeen penetrated, risk of water production could not bediscounted. Completing the well in one stage would makeidenttilcation of significant water producing intervalsextremely ditlicult.

The first perforation stage would include 240 feet ofinterval from 5,210 to 5,325 and 5,355 to 5,480 ft MD, whichcorrelates to the PA sublayer. If correlations are correct, theAU sublayer was excluded from this first stage because the400 kHz resistivities had dropped quickly, indicating highwater saturation, Tubing conveyed perforating tools with fourshots per foot and 90° phasing were used to complete the firstproducing interval. Sixty bbl of treated SOZ-produced waterwere in the well when it was perforated.

Artificial lift design included a conventional pumpingunit. Details on the pump, tubing and rod design are shownin Fig. 5, A jack shaft was employed on the pumping unit tolower the stroke rate to 3,1 SPM. After testing the well at ahighly reduced rate of 193/2/3 OWG and having encouragingresults, the jack shaft was removed and the well then pumped

at 350/8/5 OWG. The fluid level began to drop andeventually fell to the pump intake. The rate graduallyreduced and was at 300/1/24 OWG when Phase I testingceased.

After testing the first stage for 34 days, the rods and tubingwere pulled and a workover tubing string was run to thebottom of the well. Surprisingly, there was no indication ofany fill along the lateral length.

For the second stage, 340 feet of perforation intervalbetween 4,570 to 4,750 and 4,780 to 4,940 would be added tothe 240 feet of the first stage, for a total of 580 feet. Both theAU and PA subsands would be perforated in the second stage.

Several artificial lift designs were considered, and it wasdecided that the original 2 7/8 tubing would be replaced with3 1/2” production tubing, using a 2 1/2” insert pump for adesign rate of 500 bbUday. The well was returned toproduction and the first gauge was 433/55/20 OWG. Someminor sand production of 0.3°A was recorded in this first testof the second stage. Water production has decreased and oilproduction has increased after the first gauge,

Well 27H-1 lG is currently the highest oil producer in theSOZ. It produces at 4 and 13 times the rate of vertical offsets27-1 lG and 77A-1OG respectively. Total cost of the 27H-I lGwell was approximately $1.2 million as compared to a typical

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SPE 35668 JAMESHARDIN, JIM MARTIN, JOE DAVIDSON, MARTIN PAULK 7

vertical well of approximately $330,000. Opportunities existto significantly reduce the cost of follow~n prospects,

Conclusions

The first horizontal well in the SOZ of the Elk Hills fielddemonstrated that substantial increases in the production ofthis mature reservoir can be achieved. Some other lessons canbe taken from the experience, and are summarized below.

1, Near-bit geologic steering contributed to the successtiddrilling and completion of this well.

2. Experience resulting from 27H- 11G indicates that isolationof potential wet zones by a cemented horizontal liner appearsfeasible in the SOZ, based upon initial production results,

3. Lost circulation or differential sticking did not pose seriousproblems in this low pressure, poorly consolidated sandreservoir,

4. Clearances between the lateral hole and liner diametersshould be adequate to permit rotation of the liner throughoutthe cementing operation,

References

1. H. Dykstra, aod W. Dickinson: “011Recovery by GravIry Drainage InfoHonzormd Wells Compared w rh Recovety f rom Vertmal Well ” paperSPE 19827 presented at the 1989 SPE Annual Tect ilcal Conference andExhibition San Antonio, Texas, October 8-11,

2. R.L.Noy: “Pressure Drops m Honzontol Wells: Men Can The,v BeTgrzored?” presented at the 19 92 SPE Annual Tectuical Conference andWashington. DC, October 4-7.

Acknowledgments

The authors express their gratitude to the Unit at Elk Hills

for allowing the writing of this paper. A special thanks to allof the many experts who participated in a team effort toensure the project was given its highest chance of success.Editorial contribution of Frank Radez is gratefidlyacknowledged,

TABLE 1. STATISTICS FOR HORIZONTAL WELL 27H-I 1G

Item I Horizontal Well 27H-1 IG Vertical Well27-11 G

Producing Interval (ft)

Planned Actual Actual

1st 2ndStage Stage

1,200 240 380 38

Reserves (MSTB) I 589 I—

I

1

1P(bbl) 325 350 490 110

Initial Water Cut (%) 30 0.3 2 40

Stratigraphic Net Pay 37 9 27 37Thickness (ft)

Dip (degrees) 30 30 30 30

cost (x$1 ,000) I Planned I I Est Vertical 1,000 1,200 330

Reservoir Characteristics

Permeability 500-1000 md

Reservoir 160 PSIPressure (Static)

NOTES:1. The 240 ft stage one is alsoincluded in stage two.2. Planned reserves and 1P arerisked predictions prior to drilling.

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8 Planning the First Horizontal Well for the Shallow Oil Zone at Elk Hills Field SPE 35668

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Figure 2. Vertical Log, Well 77A-1OG


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SPE 35668 JAMES HARDIN. JIM MARTIN. JOE DAVIDSON, MARTIN PAULK 9

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Figure 3, Structural Map, Location of Well 27H-1 lG

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Figure 4. Well 27H-1lG Profile

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Planning the First Horizontal Well for the Shallow Oil Zone at Elk Hills Field SPE 35668

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Figure 5. Proposed Production Configuration of Well 27H-1 lG

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SPE 35668 JAMES HARDIN, JIM MARTIN, JOE DAVIDSON, MARTIN PAULK 11

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Figure 7. Actual Wellpath Plot to 9 5/8” Casing Point


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12 Planning the First Horizontal Well for Ihe Shallow Oil Zone at Elk Hills Field SPE 35668

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Figure 9. Actual Resistivity Log at TD

00035668 planning the first horizontal well in elk hills.pdf

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