Copyright 2001, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 2001 SPE International Thermal Operationsand Heavy Oil Symposium held in Porlamar, Margarita Island, Venezuela, 12-14 March 2001.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to an abstract of not more than 300words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

AbstractPetrozuata, C.A is a joint venture (JV) company betweenConoco Orinoco Inc. and PDVSA. This JV is developingextra heavy crude in a 74,000-acre block in the Zuata field inthe western portion of the Faja del Orinoco in Venezuela.

After the initial single lateral wells were brought onproduction an opportunity was identified to change thedevelopment program to multilateral wells in order to increaseproduction rates. The geometry of multilateral wells isdesigned to fit the actual sand distribution and depositionalenvironment that ranges from subarial fluvial to marine tidalsystems. The various forms of multilateral wells drilled by theJV include stacked dual lateral, stacked triple lateral,gullwing dual lateral, gullwing triple lateral or crows foot,and pitchfork dual lateral wells . In addition a fishbonemultilateral concept consisting of a spine or main lateralwith liner connected to many ribs or fishbones without linershas been used in single lateral and multilateral configurations.The geologic and geographical reasons for drilling thesedifferent types of multilateral wells are reviewed. The resulthas been an increase in production rate per well that is nearlyproportional to the effective lateral length connected to thewell bore at a lower cost than possible with single lateral wellsof the equivalent length.

IntroductionPetrozuata, C.A. is a joint venture company between ConocoOrinoco Inc. and PDVSA and is referred to as the Company orthe Operator in this document. The Company is developingextra heavy crude in a 74,000-acre block in the Zuata field in

the western portion of the Faja del Orinoco in Venezuela(Figure 1). Built from the ground up in less than three years,Petrozuata has drilled over 306 horizontal laterals forproduction and 137 vertical wells for information. Oilproduction has exceeded 100 MBOPD with plans to reach 120MBOPD in 2001. It is the worlds largest multilateraldevelopment. Each horizontal well is custom designed andgeosteered to assure efficient reservoir access based 3Dseismic, vertical stratigraphic well control and detailedgeologic facies maps.

In 1996 the Company finalized the basic development planto primarily use single lateral horizontal wells under depletiondrive with no thermal stimulation or other pressure supporttechniques to produce 120 MBOPD for 35 years. The projecthas an early production period prior to the 35 year plateauperiod to allow developing the 120 MBOPD productioncapacity while a delayed coking upgrader is constructed nearJose on the northern coast of Venezuela (Figure 2).

The basic well layout in this plan is to center horizontallaterals of 1200 meters length within drainage rectangles 600meters wide by 1600 meters long (Figures 3 & 4). Since thereservoir consists of multiple sand bodies that may be locallyisolated but are generally interconnected on a field-wide scale,horizontal wells are placed vertically above each other asneeded to develop the stacked sand bodies within localdrainage rectangles. Generally Electric Submersible Pumps(ESPs) are used initially and Progressive Cavity Pumps(PCPs) are planned as well rates decline. Downhole andsurface dilution with a light crude oil, or naphtha returnedfrom the upgrader, is used to improve viscosity anddehydration.

After shooting 3D seismic in 1996 and 1997, the Companystarted drilling in mid 1997. First oil production startedAugust 1, 1998 and, with the drilling of additional wellsduring the early production phase, production ramped up toover 90 MBOPD by mid-year 2000. The project should enterthe 120 MBOPD 35-year plateau in 2001 after the upgrader isfully functional.

The first 95 wells were drilled according to the initialdesign advancing the learning curve for drilling longhorizontal wells in this rather complex fluvial dominatedgeologic setting. During the early production months the

SPE 69700

Multilateral-Horizontal Wells Increase Rate and Lower Cost Per Barrel in the ZuataField, Faja, VenezuelaJohn L. Stalder, SPE, Gregory D. York, SPE, Robert J. Kopper, Carl M. Curtis, and Tony L. Cole, Petrozuata, C. A.,Jeffrey H. Copley, Kupecz-Copley Associates

2 JOHN L. STALDER, GREGORY D. YORK, ROBERT J. KOPPER, CARL M. CURTIS, TONY L. COLE, JEFFREY H. COPLEY SPE 69700

Company recognized that the development program could beimproved by accelerating the use of multilateral wells. Thiswould increase oil rate per well, increase ultimate recovery perwell, and decrease cost per barrel of oil developed since therate and recovery advantages outweigh the increase in wellcost.

Geologic OverviewRegionally, Zuata is on the southern flank of the east-westtrending Eastern Venezuela structural basin with sedimentsdipping 3-4 degrees to the north. Sediments range in age fromPreCambrian igneous-metamorphics of the Guayana Shield, toRecent (Las Piedras-Mesa Formations)1. The main oil bearingreservoir comprises Lower Miocene sands of the OficinaFormation. The Oficina Formation in Zuata field was initiallycharacterized as having high net-to-gross sands with highlateral permeability, connectivity and Kv/Kh ratios. The mainreservoir interval was initially interpreted as being depositedby large high-net-to-gross fluvial river systems that intersecteach other and amalgamate to form continuous sheet sands. Inthis geologic environment, lateral accretionary point barscharacterize the many sinuous channel systems and aretypified by highly ordered, relatively constant thicknessdeposits. Channel belts comprised of multiple episodes ofpoint bar deposition, fluvial erosion and re-deposition resultedin the multistory, amalgamated sand bodies which werethought to dominate the depositional setting in the Zuata area.

Based on this model one 1200-meter long horizontal wellcould drain a 1600-meter by 600-meter rectangular areaassuming that the sand target would be relatively continuousacross this drainage area (Figure 5). On average a well wouldtypically encounter 80% sand over its entire length but thesand itself would be continuous in the sense that the wellmight cross discontinuous baffles, silt lenses, or make minordrilling excursions into the silt above or below the drillingobjective. Figure 6 illustrates such a conceptual geologicalmodel2 along side of a photograph of the modern OrinocoRiver.

Development drilling and production testing in 1998 and1999 produced a less continuous picture of the sand deposits.While some horizontal wells encountered a significantpercentage of net sand in the wellbore (Figure 7), many otherhorizontals encountered significant intervals of silt andoccasional shale breaks (Figure 8). Linear net-to-gross ratiosin the horizontal laterals averaged 75% with a mode ofapproximately 90%. Although the net-to-gross well loginformation was not greatly different from the originalassumptions, the nature of the non-sand portions took on adifferent meaning suggesting more extensive non-pay featuresand generally a more chopped-up pay section.

In late 1998 an extensive data acquisition program waslaunched to better characterize the reservoir. Within two years137 vertical stratigraphic wells had been drilled in addition to12 exploratory wells PDVSA had drilled in the project area inthe early 1980s. Three full cores and over 2000 sidewall coreswere collected and used for sedimentological, biostratigraphic,geochemical and petrophysical studies. Image logs were

acquired in three of the wells from which whole cores weretaken, and in three of the other vertical stratigraphic wells.These logs were used as part of the ongoing reservoircharacterization work, in particular in the evaluation of whichportions of the reservoir could most benefit from theutilization of the fishbone type well. Checkshot surveys andVSPs were combined with the synthetics generated for each ofthe vertical wells and matched to the 3D seismic, then cross-correlated to generate time-depth pairs for each well andprovide a robust and accurate depth model for the field. Theseismic data volume has been improved from the originalvolume over the course of a few iterations. The currentvolume has benefited from spectral balancing to increasebandwidth, a more effective statics adjustment to correctwavelet distortion within the stacked trace, and a dip moveoutcorrection (DMO) which also sharpens the stacked trace.

The ensuing reservoir characterization indicated a morecomplex depositional scenario. As compared to the basis ofdesign, there are fewer sands thicker than 50 feet (15 meters)and the sands are generally less interconnected. The geologicmodel was modified from what was dominantly a high net-to-gross relatively predictable fluvial depositional environment toa more complex model containing a mix of fluvial,distributary and tidal estuarine channel deposits. Repeatedbase level cycles are observed as episodes of channel incision,progradation, paleosol development and subsequenttransgression. In some portions of the reservoir, a more marineinfluence is indicated by bioturbation and tidal and wavedominated sedimentary structures present in the full cores.Sand deposited in this proximal marine environment hasvariable net-to-gross ratio and lower Kv/Kh connectivity.

The fluvial system in the Zuata area trends from thesouthwest to the northeast (Figure 9). Petrozuata generallydrills its wells in an east-west direction. This layout oftenresults in laterals cutting across multiple depositional channelsproviding a better drainage pathway between the sand and thewellbore. Without this wellbore interconnection some portionsof the sand would have to drain through a more-lengthy pathrelying exclusively on sand body intersections outside thelocally defined drainage area for a given pad.

The average channel belt ranges from 1 to 8 km wide inthe Zuata area with an average bed thickness of about 30 feet(9 meters). Most of the oil is in beds that are between 20 and40 feet (6-12 meters) thick. Thickness-to-width aspect ratiosfor the channel systems currently targeted in this stage of thefield development range from 1:17 to 1:30. The channelsystems appear to range from 600 to 1100 feet (180-335meters) wide in this area.

Each lateral is geosteered using 3D seismic, geologicinterpretation and mapping to maximize sand content andoptimize lateral placement. The well planning and geo-steeringmethodology is based on the accurate conversion of the seismicdata to depth. The velocity model incorporates data from nearly150 vertical wells where time-depth relationships aredetermined through correlation of the log response with theseismic data. These results are further enhanced by checkshotsurveys at 20% of the locations. The second key part of the

SPE 69700 MULTILATERAL-HORIZONTAL WELLS INCREASE RATE AND LOWER COST PER BARREL IN THE ZUATA FIELD, FAJA,VENEZUELA 3

process is the interpretation of major geologic boundaries,which were identified in the data and correlated between welllogs. Finally the depositional facies model is used as anindication of the expected net pay and its architecture. Lateralsare planned in partnership by a team of geological, drilling,reservoir and completion representatives. During drilling, thelithologic information is plotted on the seismic, and thisinformation is used to refine the calibration of the seismic /lithologic interpretation. This is important because the seismicrecognition of sand is not always straightforward and the localcalibration at the drill bit is the final critical information. Ifchange in the original drilling plan warrants, modifications inthe well path may be made, in real time, to optimize the amountof sand drilled.

Results from drilling some 321 horizontal laterals showedthat, on the average, a lateral encounters four 1100 feet (335meters) wide, oil-bearing sand bodies having reservoir quality.Sand bodies in this context are defined as having more or lesscontinuous resistivity greater than 20 ohm-meters. Resistivitybreaks that fall below 20 ohm-meters along the drilled path aretaken to be non-continuous silt or shale baffles when less than100 feet (30 meters) in length. Silt or shale sections greaterthan 100 feet (30 meters) along the drilled path denote aboundary between sand bodies.

On average laterals encounter 73% net oil over an averagelateral length of 1441 meters. With 600-meter well spacing,an average lateral connects to an estimated 14.6 million STBof original oil in place (Figure 10).

Single Lateral Well DesignThe initial design of the wells called for 150 meters of 13-3/8inch casing set vertically. The build section of the well wasdrilled with a 12-inch bit. Dogleg severity was limited to8/100 feet (8/30 meters) above the pump tangent and 6-10/100 feet (6-10/30 meters) below the tangent. The 12-inch hole was landed 370 meters due east or due west of thepad. At that point 800 meters of 9-5/8 inch casing was runand cemented with the casing shoe approximately horizontal.Then the 8-inch horizontal section was drilled andcompleted with 1200-1500 meters of 5.5-inch or 7-inch slottedliner (Figure 11).

Single Lateral PerformanceSingle lateral production performance showed that generallywells with longer effective length produced at higher ratesthan shorter wells (Figure 12). Effective length is definedhere as the horizontal section length that exhibits greater than20-ohm-meter resistivity. Although this should be no greatsurprise, effective length seems to be more significant thanany other single parameter that differentiates one well fromanother in this project. Sand thickness measured at the verticalstratigraphic well for each drilling pad was expected to be avery significant determinant of well performance, but seemsless consistent as an indicator of production performance asshown in Figure 13. Localized variation in oil gravity from 8.4to 10 API, viscosity, or temperature seemed much less

influential than the effective length parameter. Generalreservoir properties are summarized in Figure 14. The WS4Asand has a lower productivity than the other members of thereservoir as a result of a more marine influenced fluvialsetting, but within this sand effective length largely determineswell productivity as in other parts of the reservoir.

From a practical drilling perspective, the Company founddiminishing return on trying to extend the horizontal lengthmuch beyond 1850 meters due to the shallow depth (2000 feetor 610 meters TVD), the unconsolidated sand, and thedifficulty of running liners to greater horizontal distances. Thelongest 7-inch slotted liner run to date in this operation is 6604feet (2013 meters) as measured from the liner shoe to the 9-5/8-inch casing shoe. Even without drilling limits one wouldexpect friction drop along very long horizontal sections toresult in a diminishing advantage for increasing well length.

Multilateral Drilling ConceptsThe Company started drilling multilateral wells to developportions of the reservoir that could be reached from a singlesurface location so as to increase well rates while maintainingmanageable lateral length. Several different well designs areused to fit the particular geologic and geographic features ateach well pad. Each multilateral well is custom designed toeffectively connect and develop the reservoir in an effectiveand economical manner.

Stacked Dual Lateral Wells. The first design change was toimplement a stacked dual lateral well (Figure 15). Like thesingle lateral design, 9-5/8 inch casing is landed 370 metersdue east or due west of the pad and the lateral is drilled andlined with 7-inch slotted liner. Then a window is cut in the 9-5/8 inch casing above the first lateral and a second lateral isdrilled. Seven-inch slotted liner is tied back into the casingstring above the first lateral. Depending on the true verticaldepth of the upper sand target, the pump tangent section iseither located above or below the window exit and linertieback. The current design keeps the tangent section for theartificial lift less than 50 meters TVD above the lower lateral.

Fishbone Wells. The second design innovation is called thefishbone well. The first fishbone wells were drilled due east ordue west of the pad as single lateral wells with 5 to 9fishbones or ribs drilled off the spine of the lateral. Theribs arc away from the spine and generally extendapproximately 300 meters away from the spine. At the sametime the ribs cut vertically 7 to 30 meters through the section.The ribs are designed to penetrate laminated flow barrierswithin sands and to better contact locally disconnected sandlenses. The ribs have no liner, but the spine has 7-inch slottedliner as used in most of the other wells. As the design anddevelopment plan has progressed the fishbone concept, attimes, has been used in combination with all the other welldesigns discussed here. Figure 16 shows fishbones used with astacked dual lateral well.

4 JOHN L. STALDER, GREGORY D. YORK, ROBERT J. KOPPER, CARL M. CURTIS, TONY L. COLE, JEFFREY H. COPLEY SPE 69700

The fishbone concept has merit in homogeneous sands inthe sense that very viscous oil has a shorter distance to travelto a rib than having to flow through the sand to reach thespine. This advantage primarily yields an acceleration ofrecovery. A greater advantage occurs in non-homogeneoussand having barriers, baffles or permeability restrictions. Inthese instances the ribs actually provide a direct connection toa portion of the reservoir that would otherwise have to followa tortuous or restricted pathway to the producer. The conceptcan also be used to access limited sand bodies that could notjustify a separate well or conventional lateral when thesebodies are separated from the body containing the spine.

Gullwing Multilateral Wells. The Companys thirdmultilateral well design is the gullwing well. This concept wasdesigned to develop the 600 meter by 1600 meter drainagerectangles due North and due South of existing pads withouthaving to construct new well pads centered in those rectangles(Figure 17). This well design alone is expected to save 50 to70 surface pads over the life of the development.

The gullwing well follows the same basic casing designexcept the build section of the well is drilled in the due northor due south direction. The horizontal sections of the well arestill targeted to begin 370 meters due east or due west of thepad center. The first lateral is drilled due east or west and thesecond lateral is drilled in the opposite direction out of awindow section with the liner tied back to the 9-5/8 inchstring. The radius of the turn to bring the well path in the eastor west direction has been accomplished with doglegs up to20/100 feet (20/30 meters).

Triple Lateral Wells. After gaining experience drilling andcompleting the stacked dual, gullwing and fishbone typemultilateral wells, the progression led to triple lateral wells.There are several variations of the triple lateral well beingdrilled at the current time. Each of the well types mentionedabove can have a third lateral added. Currently there arestacked triple laterals in two dimensions and in threedimensions. One triple lateral design that serves two distinctpurposes is the crows foot triple lateral well.

Crows Foot Triple Lateral Well. The crows-foot wellcombines the concept of draining adjoining 600 by 1600-meter drainage rectangles with a gullwing well andaccelerating the production from under an adjacent pad. In thecourse of drilling a standard pad configuration with wellslanded 370 meters due east and west of the pad, there is a 740-meter wide strip under the pad that does not drain uniformlywith the rest of the area feeding the wells. By drilling acrows foot triple lateral well, the gullwing drains the adjacentareas and the central third lateral under the adjacent padaccelerates the production from the 740-meter wide fairway.This concept is illustrated in figure 18.

Pitchfork Dual Lateral Well. The pitchfork well design hastwo parallel laterals at the same stratigraphic depth heading inthe same general direction to drain adjacent areas of the

reservoir. This design is less common but fills a certain nichewhen stacked duals and gullwings are not a good fit for thelocal geologic picture.

Well Design Fitting The GeologyUsing a combination of well types, a design can be tailored toaccess the oil in several adjacent areas with fewer pads andwells than the original design would have required. Figure 19shows Petrozuatas multilateral development of drainagerectangles L16 L20 and M16 M20. The two well clustersare centered between L17 and M17 and L19 and M19respectfully. The rectangles containing the surface pads aredeveloped with stacked multilateral wells and one singlelateral well. The adjacent rectangles are developed withgullwing, gullwing with fishbones and a triple lateral crowsfoot.

Multilateral Well Cost EffectivenessThe relative cost of drilling and completing a 9-rib fishbonewell is 1.18 times the cost of a single lateral well. The relativecosts for other wells are: stacked dual lateral 1.58, gullwingdual lateral 1.67, and the more complex crows foot triplelateral 2.54 times a single lateral well. Petrozuata has foundthat the production rates gained with these various designsmake the investment worthwhile. In a general sense this canbe seen in Figure 20 comparing single lateral and multilateralwell rates.

A similar result is apparent for fishbone wells as shown inFigure 21. The two earliest WS3A fishbone single lateralwells show improved productivity relative to the other 14WS3A single lateral wells. These two fishbone wells appear tohave accelerated recovery and still show enhancedproductivity after 12 months of operation.

Multilaterals Allow Greater DepletionOne advantage of multilateral wells is that the reservoir can bedepleted to a greater extent than single lateral wells wouldallow. For example, suppose that a single lateral well has aneconomic limit rate of 50 BOPD. That same lateral whencombined in a dual lateral configuration with an identicallateral in another sand target might effectively produce downto 25 BOPD before reaching a 50 BOPD economic limit forthe dual lateral well. A triple lateral well should allow evengreater recovery.

Multilateral RisksOf course there can be risks with multilateral wells related toexposure to water or free gas. In such a case one branch mayjeopardize the entire well and remedial action may be needed.Fortunately water is relatively predictable in this portion of theFaja and generally can be avoided. Most free gas in the areaoccurs in thin, discontinuous sand packages often situatedadjacent to coal beds. Typically such gas is not detectable withseismic, but has occasionally shown up in limited sections ofsome horizontal and vertical wells. Operations to date indicatethat limited gas pockets of this type are not much concern.

SPE 69700 MULTILATERAL-HORIZONTAL WELLS INCREASE RATE AND LOWER COST PER BARREL IN THE ZUATA FIELD, FAJA,VENEZUELA 5

The mechanically more complex multilateral well alsomay require more expensive repair procedures in the future.Sand control at the junctions in multilateral wells could bemore difficult than in single lateral wells, but the Companyhas had relatively few problems in this regard as junctiondesigns have evolved. This by itself would be a topic for aseparate technical paper.

Finally the multilateral concept may result in initial pumpsettings higher above the production interval for some portionsof stacked multilateral wells. This increased backpressurecould limit productivity or ultimate recovery to some extent.However, most of the wells drilled in this operation have notsuffered a pump setting elevation increase due to themultilateral design. For the few that have this problem, itshould be possible to compensate by moving pumps deeperwhen rates are low enough to set smaller pumps below thetangent sections.

Conclusions1. Various multilateral well designs have increased well

productivity, increased estimated ultimate recovery per well,and decreased cost per barrel of oil developed in thePetrozuata operation.

2. The fishbone well design shows promise of increasinglong-term productivity in homogeneous sands and increasingultimate recovery and rate in heterogeneous sands when ribscross barriers to tap sections of the reservoir that wouldotherwise drain more slowly if at all.

3. Multilateral and fishbone wells are expected to yield ahigher recovery factor than single lateral development bycombining late life declining rates from multiple targets thuskeeping the wells above an economic limit rate for longerperiods.

4. The multilateral development, especially the gullwingwell, reduces the overall number of pads to drain the availableacreage. This reduces cost per barrel and environmentalimpact for the project.

AcknowledgementThe authors wish to thank Petrozuata, C.A. and its parentcompanies, Conoco Inc. and PDVSA, for the opportunity to beinvolved in this project development and to publish this paper.Credit for the innovations and production results presentedbelong to the entire Petrozuata technical and management staffrather than the few of us listed as authors.

References1. Clancy, Thomas F.; Kelly, C.A.; Duque, Luis; Concentric Coiled

Tubing Well Vacuuming Technology for Complex HorizontalWells in Eastern Venezuela SPE Paper 60696, presented at the2000 SPE/IcoTA Coiled Tubing Roundtable, Houston, TX 5-6April 2000.

2.Galloway, W. E. and Hobday, D. K., Terrigenous ClasticDepositional Systems, Springer-Verlag, 1990.

6 JOHN L. STALDER, GREGORY D. YORK, ROBERT J. KOPPER, CARL M. CURTIS, TONY L. COLE, JEFFREY H. COPLEY SPE 69700

Fig. 1 - Project location in Zuata region of Venezuelan Orinoco Belt.

Puerto La Cruz

Ciudad

Guayana

CARACAS

JOSE

ZUATA

Pariaguan

CiudadBolivar

Maracaibo

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VENEZUELA

ORINOCO BELTPRODUCTION SITE

UPGRADER SITE

Fig. 2 - Integrated operations during 35-year project to produce andupgrade 120 MBOPD extra heavy crude oil.

30 MBPCD20" Diluent Pipeline

Byproduct SalesCoke, Sulfur, &LPG

FUEL COKE3000 TPD

150 MBPCD36 "Diluted Oil Pipeline

57 MBPD @ 20 API7.5 MBPD @ 14 API

PDVSA CardnRefinery

32 MBPD @ 27 API - Synthetic Crude7.5 MBPD @ 14 API - FCC Feed

Lake Charles Refinery

120 MBOPD Zuata AreaFaja Del Orinoco

Jose CrudeUpgrader

Synthetic Crude Sales104 MBPCD

Fig. 3 - Basic drainage area for two 1200-meter horizontal wells drilledfrom a centralized surface pad.

1600 meter 1600 meter

600 meter1200 meter1200 meter

Pad

Fig. 4 - 74,000 acre project area divided into 600-meter by 1600-meterdrainage rectangles.

3200 m

600 mWell Cluster

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Fig. 5 - Well pads, stratigraphic and horizontal wells, and 1600 x 600meter drainage rectangles superimposed on a typical geologic setting.

After Galloway 1990

OrinocoRiver

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Lateral

Fig. 6 - Depositional bars in the Orinoco River and conceptual blockmodel of grain size, lithology and log response for a horizontal well.

SPE 69700 MULTILATERAL-HORIZONTAL WELLS INCREASE RATE AND LOWER COST PER BARREL IN THE ZUATA FIELD, FAJA,VENEZUELA 7

Fig. 7 - Some wells encounter very high quality oil bearing sand overmost of the drilled section as shown by IJ27-3 horizontal well log.

Yellow = sand by gamma ray

Red = net oil: resistivity > 20 ohm-meter

Bands show zones of 20, 30, 50, and 100+ ohm-meter resistivity

Fig. 8 - Other wells encounter shorter intervals of oil bearing sand withsignificant silt sections as shown by horizontal well logs from IJ27-4.

Green = non-pay silt or shale: resistivity < 20 ohm-meter

Green = non-pay silt or shale on gamma ray log

Fig. 9 - Channels trend northeasterly in seismic amplitude map.Integrating well control allows accurate depositional interpretation.

E19P-1E19P-1

E20P-2E20P-2

Area ofPoint BarDeposition

Main Channel

RMS Amplitude MapInterval. WS3 to 135 above (40 ms)

N

Fig. 10 - Distribution of Oil In Place connected to 1200 meter lateralswith 600-meter by 1600-meter spacing.

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Fig. 11 - Basic single lateral well with 7-inch slotted liner, possibledownhole diluent string, and ESP or PCP lift.

Fig. 12 - Effective horizontal length strongly influences oil productionbased on production from 86 single lateral wells.

86 Petrozuata Single Lateral Wells:Cum Oil vs Effective Length

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8 JOHN L. STALDER, GREGORY D. YORK, ROBERT J. KOPPER, CARL M. CURTIS, TONY L. COLE, JEFFREY H. COPLEY SPE 69700

Fig. 13 - Vertical well log pay thickness is not a consistent indicator ofhorizontal well productivity based on 82 single lateral wells.

82 Petrozuata Single Lateral Wells:Cum Oil vs Pay Thickness

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Fig. 14 - Reservoir properties are typical of shallow unconsolidatedheavy oil sands in the Faja and elsewhere.

depth 1700-2350 ftporosity 30-35%permeability 1-17 darcytemperature 100-135 Fgravity 8.4-10 APIgas oil ratio 60-70 SCF/BOviscosity..deadviscosity..live

5000+ cp1200-2000 cp

sand character unconsolidatedcompressibility 80-90 x 10-6 psi-1

initial pressure 630-895 psi

BASIC RESERVOIR PROPERTIES

Fig. 15 - The stacked dual lateral well has an upper lateral added througha window cut in the 9-5/8 inch casing of a single lateral design.

STACKED MULTILATERAL WELL SCHEMATIC

16 hole

500~600 ft

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12 1/4 hole

2000~2500 ft

9 5/8 Casing

7 Slotted Liner

Completion String

ESP or PCP pump

with diluent injection

8 1/2 hole

6000~9000 ft

Stacked Dual Lateral Fishbone Well

BC17-2

33,753 ft Drilled in 19 Days; 19,410 ft Net Pay (58%)

Fig. 16 - The fishbone wells ribs improve productivity with highercapacity conduits and by crossing flow baffles and barriers.

Fig. 17 - The gullwing well accesses the drainage rectangles adjacent tothose containing the well pad saving the cost of additional well pads.

Gullwing Step Out Development

B 20B 20

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Fig. 18 - The crows foot well adds a central lateral to a gullwing toaccess the 740 meter fairway between heels of wells on an adjacent pad.

26,430 ft Drilled; 18,791 ft net pay (71%)

LM17-6

SPE 69700 MULTILATERAL-HORIZONTAL WELLS INCREASE RATE AND LOWER COST PER BARREL IN THE ZUATA FIELD, FAJA,VENEZUELA 9

Fig. 19 - Two adjacent pads are developed with a combination of stackeddual lateral, gullwing, crows foot, and fishbone multilateral wells.

LM19 & LM17Pads

LM19 Pad53,827 ft Drilled

43,693 Net pay (81%)4 Multilateral wells

LM17 Pad108,833 ft Drilled

81,555 Net pay (75%) 4 Multilateral wells

Fig. 20 - Multilateral wells achieve higher rates shown in thiscomparison of 94 single lateral wells with 19 multilateral wells.

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1400

1600

1800

2000

2200

0 1 2 3 4 5 6 7 8 9 10 11 12

SINCRONIZED TIME (Months)

Ave

rag

e R

ate

Per

Wel

l (B

OP

D/W

EL

L)

94 SINGLE HORIZ. WELLS 19 MULTI-LATERAL WELLS

Fig. 21 - Fishbone wells higher rate per 1000 feet of net pay measuredalong the spine shows that ribs boost productivity over single laterals.

WS3A Sand: Fishbone Wells versus 14 Single Lateral Wells

0

50

100

150

200

250

0 6 12 18 24

Months

MB

O/1

000

ft>2

0 oh

m-m

14 Single Lateral Wells2 Fishbone Wells(spine length only)

2 Fishbone Wells(spine + rib length)