spe-148803-pa (numerical simulation of steam-assisted gravity drainage with vertical slimholes)

Numerical Simulation of Steam-AssistedGravity Drainage With Vertical Slimholes

J. Chang, Devon Canada; and J. Ivory and C. Tunney, Alberta InnovatesTechnology Futures

Summary

Steam-assisted gravity drainage (SAGD) is the primary in-siturecovery method for bitumen from the large Athabasca deposit inAlberta, Canada. SAGD field operations encounter a significantdecrease in production performance when low-permeability shalebarriers are present in the formation. These layers can reduce SAGDperformance and impede the growth of the steam chamber. Theyalso significantly limit the percentage of the deposit from which bi-tumen can be economically recovered with SAGD. The concept ofdrilling vertical slimholes to create flow paths through barriers wasconceived and investigated at Alberta InnovatesTechnologyFutures (AITF), formerly the Alberta Research Council. The use ofslimholes has the potential to significantly increase the amount ofrecoverable bitumen (reserves) and the rate at which it is producedduring SAGD. For shallow reservoirs, the slimholes could be drilledfrom the surface at a relatively low cost. It is believed that the pro-cess can be economically viable after its technical operation hasbeen optimized with improvements in drilling technology, slimholesize and spacing, and enhanced usage of the slimholes in the devel-opment of steam chambers above the shale layers. Alternatively, theslimholes could be drilled from the horizontal wellbores (to avoidsurface disturbance) as either horizontal slimholes from the pro-ducer or as horizontal/vertical slimhole combinations from theinjector.

The 2D and 3D field-scale numerical simulations were per-formed by use of reservoir properties and operating conditionsbased on published information for the MacKay River SAGDoperation in the Athabasca deposit. The reservoir depth was 135m, the initial pressure 500 kPaa, the initial temperature 7.5C, andthe initial oil saturation (SO) 0.8. The simulations explored theeffect of vertical slimholes, which were laterally offset 7 m fromthe horizontal well-pair in reservoirs with and without shale layersor shale lenses. The effects on SAGD performance that wereinvestigated were slimhole cross section (25 cm 25 cm or 50 cm 50 cm), the distance between slimholes (12 or 24 m) in thedirection parallel to the well pair, the permeability of the reservoirand the vertical slimholes, and horizontal slimholes from the in-jector or producer. The slimhole cross section represents the dis-turbed area adjacent to the drilled slimhole and the drilled holeitself and is therefore relatively large. The slimholes were repre-sented as high-permeability vertical channels by use of refinedgrids. For a reservoir with a continuous shale layer, SAGD per-formance was improved by vertical slimholes because of the re-covery of previously inaccessible oil from above the shale layer,where a secondary steam chamber was formed.

Introduction

After Saudi Arabia and Venezuela, Canada has the third-largestoil reserves in the world. Of Canadas 28.5 billion m3 of oilreserves, 27 billion m3 is bitumen in Alberta that is consideredeconomically recoverable with current technology. This reservesestimate could be increased to as much as 50 billion m3 withimproving technology (Government of Alberta 2010). The Atha-basca deposit is the largest of three major oil-sand deposits in

Alberta (Fig. 1) in which the original bitumen in place has beenestimated to be approximately 161.1 109 m3 (Energy ResourcesConservation Board 2011). The other two deposits are in ColdLake and Peace River. Another deposit (Wabasca) is connected tothe Athabasca deposit and is generally grouped with it. At reser-voir conditions, bitumen is too viscous to flow and is producedeither by surface mining after the overburden has been removedor by in-situ methods. The majority of oil-sand production is cur-rently carried out by surface mining, but in-situ production willexceed it in the future because 80% of Albertas bitumen depositsare too deep for surface mining. Most of the accessible bitumen inthis deposit will be recovered by thermal processes (Table 1), andmost of the inaccessible bitumen results from a pay thickness thatis too thin (Table 2) and in which heat losses to the surroundingformations are too great for thermal processes to be economical.SAGD is unlikely to be economical for pay thicknesses less than10 m. Thinner net pays have higher heat losses to the overburdenand the underburden, and have higher capital costs per unit of bi-tumen produced because of the smaller recoverable resource.

Both SAGD and cyclic steam stimulation (CSS) are steam-basedrecovery processes used in the Cold Lake and Peace River deposits,but SAGD is the preferred option for Athabasca and has beenimplemented commercially there. Combined, these technologiesproduce a little more than 160 000 m3 of bitumen. The SAGD pro-cess was developed by Roger Butler and colleagues (Butler et al.1981; Butler and Stephens 1981; Butler 1991a, b). In this process, apair of horizontal wells is drilled into the oil sand, with an injectorapproximately 5 m above the producer (Fig. 2). Steam is injectedcontinuously into the upper well and heats the reservoir by conduc-tion and convection, thus reducing the bitumen viscosity, mobiliz-ing it, and causing it to flow into the underlying producer (Butlerand Chung 1988; Butler 1991a, b, 1992). Little of the bitumenbelow the producer is recovered. SAGD technology has existed for30 years; it was first piloted successfully at the Underground TestFacility (UTF) near Fort McMurray in Alberta, Canada (Edmunds1987; Edmunds et al. 1987, 1988, 1991, 1994; Edmunds and Gittins1993). At the UTF site, the bitumen viscosity was 5 million mPa.sat the reservoir temperature of 7C. This high viscosity is typical ofthe Athabasca deposit (Komery et al. 1998). Most SAGD commer-cial projects have come on line only within the last decade.

Because of the stratigraphy and unconformity of the regionalgeology, the Lower Cretaceous formations of the Athabasca oil-sand deposits contain extensive interbedded sand and shales(silt-, mud-, and clay-shale or silt-, mud-, and clay-stone) (IBS).IBS conditions are present in a wide area of the Alberta oil-sanddeposit. At least four unconformity-bounded and stacked succes-sions extend more than a broad area (320 300 km). Along thewestern and southern edge of the Athabasca Wabiskaw-McMur-ray oil-sand deposit, channel sands grade into finer-grainedmudstones with thin coarsening-upward sand. The rocks rangefrom tight, shales/mudstones to poorly sorted bioturbated sandysilty mudstones, to well-sorted sandstone (Hein and Marsh 2008).There are three main stratigraphic units in the McMurray forma-tion, and each contains shale or inclined heterolithic stratificationto different degrees. They are present in most SAGD operationsin the Athabasca deposit (RPS Energy Canada 2009). Operatorshave mostly already selected the prime locations for SAGD, andfuture operations will occur in locations with lower-quality oilsand. Then, shale layers will be a dominant issue that must bedealt with for SAGD to be economical.

CopyrightVC 2012 Society of Petroleum Engineers

This paper (SPE 148803) was accepted for presentation at the Canadian UnconventionalResources Conference, Calgary, 1517 November 2011, and revised for publication.Original manuscript received for review 14 October 2011. Revised manuscript received forreview 10 September 2012. Paper peer approved 17 September 2012.

662 December 2012 SPE Reservoir Evaluation & Engineering

The reservoir quality varies considerably across the hugeAthabasca deposit (Hein and Cotterill 2006). It can even varybetween well pairs at a particular location. Bitumen recoverydepends, to various extents, on bitumen viscosity, pay thickness,permeability, porosity, SO, and reservoir heterogeneity. Reservoircomplexities (e.g., interbedded shale, overlying water and/or gaslayers) can interfere with the process and reduce its effectiveness.Although operating strategy is highly important, reservoir qualityhas the greatest effect on SAGD performance. Many variables/parameters (e.g., well length, well-pair orientation, vertical spac-ing between injector and producer, lateral spacing between wellpairs, steam rate, operating pressure) can be adjusted to improvethe SAGD operation. Typically, SAGD reservoirs are selected onthe basis of pay-zone thickness (>15 m), high SO, high permeabil-ity, and high porosity.

Effective methods for recovering bitumen from lower-qualityreservoirs, such as those with continuous shale layers or multiplethin pays, are needed. The complex reservoir properties and wideranges of geological conditions require improved technology toovercome the difficulties in SAGD applications. Thin pay andIBS reduce SAGD performance and interfere with steam-chambergrowth. IBS layers are often more than 30 cm thick. They providea significant challenge for SAGD applications to overcome to besuccessful. Consequently, dealing with IBS during the SAGDprocess has become an important issue.

There are many examples of clean sands interrupted by shalelayers (Tristone Capital 2007) approximately 1 m thick, and it isdifficult for logging tools to resolve layers less than 1 m thick.Lack of pay continuity makes it difficult to attain desired produc-tion rates, and reduced well spacing may be required. Shale, if

continuous to a significant lateral extent, impedes/prevents steamrise and drainage of oil and water to production wells. It acts as abarrier to vertical-pressure transmission and rapidly transmitspressure horizontally. Extensive shale intervals between an injec-tor and producer can cut off communication between them. IBSlayers or lenses above an injector can prevent the steam chamberfrom rising to the top of the reservoir, but continued exposure tosteam may create conditions for some fluid penetration.

Thin shale layers may be broken in time because of clayswelling during SAGD. Injection of steam may increase shale per-meability because of the stresses and volumetric strain createdduring SAGD. However, these changes are likely to be insuffi-cient and cannot be relied on, especially for thick shale layers. Anexample of the presence of shale was the 1- to 3-m layer of shaleand IBS (Unit F) that was continuous through most of the UTFPhase A site (Edmunds et al. 1994). It did lie between the injectorand producer of Well Pairs A1 and A3 and was below the A2 wellpair (Fig. 3).

Operating at SAGD pressures close to the fracture pressure isone alternative to increase steam injectivity in formations withthin shale interbeds. However, this is risky because caprock integ-rity can be undermined. This is particularly important for shallowAthabasca deposits in which a steam release to the surface occurs(e.g., the one at Joslyn Creek near Fort McMurray in May 2006)(Energy Resources Conservation Board 2010). Many papers havebeen written about geomechanics, its modeling, and its effects onSAGD (Chalaturnyk 1997; Chalaturnyk and Li 2004; Collins2002 and 2005; Li and Chalaturnyk 2005, 2006, and 2009; Poo-ladi-Darvish and Mattar 2002; Touhidi-Baghini 1998; Tran et al.2005; Wan 1991), but the effect of geomechanics is still toouncertain to risk operating near the formation-fracture pressure.

Borehole mining, in which a water jet is used to create a cavitybelow the shale layer, and the oil sand is removed from the cavity,was tried at Esso Cold Lake in the 1990s (Sharpe et al. 1997). Itwas considered unsuccessful because of the collapse of the shaleroof. Overall, the best strategy may be to cause reservoir dilation,increase effective permeability in the reservoir, and rely on a strat-egy such as slimholes to create communication through shale layers.

overburden

vaporchamber Mobilized oil

Injector

Oil sandProducer

underburden

H

S

H

Fig. 2Schematic of SAGD configuration and steam chamber.

Fig. 1Alberta hydrocarbon resources (Oil Sands IndustryUpdates, Government of Alberta 2011).

TABLE 1ACCESSIBLE BITUMEN VOLUMES IN ATHABASCA

OIL SANDS AS OF 2005a

Accessible Volumes Billions of m3

Surface mining 9.4

Cold primary 2.0

SAGD, CSS 66.8

Total 78.2aWerniuk 2007.

TABLE 2INACCESSIBLE BITUMEN VOLUMES IN

ATHABASCA OIL SANDS AS OF 2005a

Inaccessible Volumes Billions of m3

Too thin 60.4

Insufficient caprock 5.8

Intermediate depth 4.4

Low-pressure gas cap 2.2aWerniuk 2007.

December 2012 SPE Reservoir Evaluation & Engineering 663

AITF has proposed and investigated an innovative technologyinvolving the use of drilled slimholes to improve SAGD perform-ance, increase bitumen recovery, and optimize SAGD applicationsfor the Athabasca oil-sand deposit (Chang et al. 2011). To under-stand and apply the proposed new technology in the field, it is nec-essary to evaluate its technical and economic feasibility. This papersummarizes numerical simulations performed to evaluate the techni-cal applicability concerning how the SAGD process can benefitfrom the use of slimholes rather than how they will be drilled. Theslimholes considered could be drilled either from the surface as ver-tical slimholes or drilled from the horizontal wellbores, to avoid sur-face disturbance, as either horizontal slimholes from the producer oras horizontal/vertical slimhole combinations from the injector.

The project primarily evaluated the use of vertical slimholes tocreate vertical pathways for fluid flow through shale layers. The ver-tical slimholes are considered to be disturbed open holes in the res-ervoir without affecting the caprock integrity or holes drilled intothe reservoir filled with a gravel pack with a porosity of approxi-mately 0.48 in the pay zone(s) to maintain structural integrity andplugged (cemented) at the top of the reservoir to prevent steam flowto the surface. The slimholes in the simulations included the dis-turbed (high-permeability) area around the drilled hole. Countercur-rent flow will occur through the slimholes. Steam and exsolved gaswill flow upward, and oil and condensed steam downward. Theextent to which these countercurrent fluid flows will interfere witheach other depends on the characteristics of the slimholes (e.g., theireffective diameter, permeability, and wettability). For example, ifthe effective diameter of the slimholes is too small, steam will risethrough them, and the drainage of condensed steam and oil will benegatively affected. The project examined the effect of the slim-holes on the steam chamber below the shale layer and if a newsteam chamber will be formed above the shale layer as shown sche-matically in Fig. 4. It determined slimhole effectiveness for an

impermeable shale layer (a 1- to 1.5-m thickness between or aboveSAGD wells), shale lenses, and homogeneous reservoirs with a ver-tical permeability/horizontal permeability (kv/kh) in the range of 0.1to 1. It also evaluated the effect of slimhole size (25 cm 25 cm vs.50 cm 50 cm) and spacing (12 vs. 24 m).

The use of slimholes has perhaps its greatest benefit for multipleshale interbeds in which it is not practical to have a horizontal-wellpair in each layer. The process can be operated so that the steamdoes not simply channel to the top oil-sand layer, leaving underly-ing oil-sand layers undrained. In particular, the pressure must firstbuild up in an oil-sand layer to displace bitumen downward so thatsteam can penetrate the shale. This pressure buildup (as explainedlater) is caused primarily by conductive heating, which means thateach oil-sand layer will be heated and drained, in turn, starting atthe bottom layer in which the horizontal-well pair is located.

Methodology

Reservoir Simulator Used in Simulations. Numerical-simula-tion models were developed to investigate the use of verticalslimholes through shale layers (Fig. 5). Although intuitively onemight think that slimholes would improve SAGD performance,this is simplistic, because it evades the complexity of the process.The simulations were effective in highlighting important mecha-nisms involved in the process. They also showed that before theyultimately improve SAGD performance, the slimholes can initiallyreduce oil production as a result of steam loss to the reservoirabove the shale layers. The simulations looked at the effect of res-ervoir type on the effectiveness of slimholes.

The simulations were performed by use of the CMG STARS(Computer Modelling Group 2012) simulator, which is based on thefinite-difference method. A Cartesian coordinate system was used.In the simulator, a gridblock is represented by I, J, and K;

2.4 m

7.4 m

5.2 m

8.8 m

9.5 m

1.7 m3.3 m

>7.5 mEdmunds et al., 1991

Fig. 3UTF Phase A stratigraphic cross section.

C

189

168

147

126

105

84

63

42

21

0

210

Fig. 4Conceptual secondary steam chambers at slimholes.

12 or 24 m

7 m

Injector and Producer wellsOpenhole channels Steam Chamber Note: not to scale

Fig. 5Conceptual model for vertical slimholes.


I represents its position as the number of blocks in the traditional x-direction, J is the number of blocks in the y-direction, and K is thenumber of blocks in the z-direction, in which K 1 representsblocks at the bottom of the formation.

Slimhole Representation in Simulations. For most simulations,the slimholes were assigned a permeability of 1,000 darcies, a po-rosity of either 0.4 or 0.48, a water saturation (Sw) of 0.5, and agas saturation of 0.5. During the SAGD preheat phase, oil quicklyentered the slimholes, and the SO increased. Some simulationswere performed with a slimhole permeability of 100,000 darciesand a porosity of 95% to determine whether the effectiveness ofthe slimholes would be improved if they had higher permeabilityand porosity (i.e., contained fewer solids). Countercurrent flow ofgas and liquid through the slimholes can be represented by adjust-ing (reducing) the relative permeability in the slimholes but wasnot done in the simulations described here.

Reservoir gridblocks were typically 1 1 m in the area inwhich the slimholes were located. Each of these gridblocks wassubdivided (refined) into 16 25 cm 25 cm gridblocks. One ofthe refined gridblocks was used to represent a 25 cm 25 cmslimhole in each layer, but a 50 cm 50 cm slimhole occupiedtwo of these gridblocks. The refined gridblocks assigned to theslimholes had the specified slimhole properties, but the other (oil-sand) refined gridblocks had the original reservoir properties. Therefined grid was also used for the simulations without slimholes.In those simulations, the original reservoir properties wereassigned to all refined gridblocks, including the gridblocks thatwere assigned slimhole properties in those simulations with slim-holes. This procedure ensured that any changes attributed to theuse of slimholes were not numerical artifacts caused by the use ofa refined grid in the simulations involving slimhole applications.

Properties Used in Simulations. Reservoir Properties. Theinitial reservoir conditions were based on two Petro-Canada pre-sentations to the Energy Resources Conservation Board in Alberta(Energy Resources Conservation Board 2010, 2011). The presen-tations were related to the Petro-Canada (now Suncor) MacKayRiver SAGD performance (Kupsch et al. 2005, 2006). In thesimulations, the initial pressure at the reservoir depth of 135 mwas 500 kPaa. The reservoir temperature was 7.5C. The initialoil-sand Sw was 0.2, and its initial SO was 0.8. An operating (pro-ducer) pressure of 1500 kPaa was used in most of the simulations.

Pressure/Volume/Temperature (PVT): Solubility Properties.The Athabasca bitumen was assumed to be initially in a livestate with an initially low CH4 mole fraction in the oil phase of0.03 [i.e., the initial gas/oil ratio (GOR) was 1.2 std m3/m3]. Theinitial GOR was low because of the shallow depth and resultinglow initial pressure.

The equilibrium concentration of a component i in the oilphase (xieqm) is determined from its concentration in the gasphase, its temperature, and its pressure. In the CMG STARS sim-ulator, the equilibrium PVT behavior is represented by the use ofK values for each component i as follows:

Ki yi=xi 1

where xi equilibrium mole fraction of i in oil phase andyimole fraction of i in gas phase.

The K value of a specific gas depends on temperature andpressure and is calculated by use of a modified version of theAntoine equation (Reid 1977),

K kv1P

kv2 P kv3

exp kv4T kv5

2

where P is pressure (kPa), T is temperature (K), and kv1, kv2, kv3,kv4, and kv5 are coefficients for specific gases.

The CH4 kv values used in the simulations were obtained fromthe CMG STARS manual and are provided in Table 3.

Oil-Phase Viscosity. The CMG STARS default logarithmicmixing rule was used to determine the oil-phase viscosity:

lnllive oil X

Xi lnli 3

where llive oil is viscosity of the oil phase and li is the pseudovis-cosity of component i.

The dead-oil viscosity and the dissolved CH4 pseudoviscosityat different temperatures are provided in Fig. 6. These values wereconsidered to be independent of pressure because its effect is minorcompared with that of temperature. The pseudoviscosity of CH4 isthe viscosity that, if used for CH4 in Eq. 3, will result in the pre-dicted value of the live oil phase that includes dissolved CH4 anddead oil. The value for the dissolved CH4 pseudoviscosity at 20

Cwas determined on the basis of measured in-house live-oil values.The CH4 values at other temperatures in Fig. 6 were estimated.

Other Properties. The Athasbasca bitumen molecular weightwas specified as 590 g/mol. Other properties used in the simula-tions are provided in Table 4. Note that the vertical (z-direction)permeability for shale was 2.5 1010 darcies, on the basis ofmeasurements performed on actual field core with IBS. Thehorizontal permeability of shale is much higher than its verticalpermeability because of its laminated structure. As such, a highervalue of 6.4 darcies was selected for the horizontal (x- and y-direc-tion) permeability of shale and also for oil sand. The horizontalpermeability of shale would have little effect on the simulations ifit is much higher than its vertical permeability.

Reservoir Types Represented in Simulations. Four differentreservoir types were considered that are qualitatively representativeof many of the reservoirs that are present in the Athabasca deposit.

Homogeneous Sand With No Shale. This reservoir typerepresented regions of oil sand with little shale presence that arecurrently being exploited. Vertical slimholes would have a muchlesser effect on these reservoirs than on more-complex reservoirswith shale present.

Homogeneous Sand With a Shale Layer. This type representsmore of a challenge to produce oil at an acceptable rate and isalso more difficult to simulate. In the simulations, the single con-tinuous shale layer was 1.0 to 1.5 m thick and was either above(K 18) (Fig. 7a) the injector or between (K 5) the injector(K 7) and the producer (K 2) (Fig. 7b). Figs. 7a and 7b

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . .

. . . . . . . . . . . . . . . . . . .

TABLE 3CH4 kv VALUES USED IN THE SIMULATIONS

CH4

kv1 (kPa) 545 470

kv2 (kPa1) 0

kv3 0

kv4 (C) 879.84

kv5 (C) 265.99

0 1

1

10

100

1000

10000

100000

1000000

10000000

0 50 100 150 200 250 300

Dead oil

CH4

Temperature (C)

Visc

osity

(mPa

s)

.

Fig. 6Dead-oil viscosity and dissolved-CH4 pseudoviscosity.


represent the same reservoir, except that the shale layer was at dif-ferent depths. Half-symmetry (reservoir split along I-axis) wasused in the simulations to reduce simulation run time. The cumu-lative injection, production, and rates must be multiplied by twoto represent the situation for a complete reservoir. Figs. 7a and 7bwere produced by the CMG graphics package with some transpar-ency to display the relative position of the shale layers, theslimholes, and the horizontal wells.

Homogeneous Sand With Shale Lenses. Fig. 8 shows thegrid structure for simulations and the locations of the shale lenses.There is an infinite number of possible configurations of shalelenses in a heterogeneous reservoir. One possible configurationwas selected for this investigation. It was designed to show theeffect that shale baffles would generally have on an SAGDperformance. Previous investigations at AITF with different butsimilar (in that fluid could move around the lenses) configurations

TABLE 4SOME PROPERTIES USED IN THE SIMULATIONS

Property Value

Porosity (%) 33 for oil sand, 27.7 for shale, 40 or 50 for slimholes

Absolute permeability in

x- and y-direction (darcies)

6.4 for oil sand, 6.4 for shale, 1,000 for slimholes

Absolute permeability in

z-direction (darcies)

3.4 for oil sand, 2.51010 for shale,531 or 1,000 for slimholes

Initial oil saturation (SO) 0.8 for oil sand, 0.25 for shale, 0.0 for slimhole

Initial water saturation (Sw) 0.2 for oil sand, 0.75 for shale, 0.5 for slimholes

Initial gas saturation (Sg) 0 for oil sand, 0 for shale, 0.5 for slimholes

Initial pressure (kPaa) 500

Initial temperature (C) 7.5Initial dead-oil mole fraction in oil phase 0.97

Initial methane mole fraction in oil phase 0.03

Oil compressibility (kPa1) 1.1106Rock compressibility (kPa1) 1.8107Rock specific heat (J/m3.C) 2.04106Rock thermal conductivity (J/m.d.C) 6.60105Water thermal conductivity (J/cm.d.C) 5.35104Oil thermal conductivity (J/cm.d.C) 1.15104Gas thermal conductivity (J/cm.d.C) 2880Steam quality 0.9

Oil specific heat (J/mol.C) 783.1Methane specific heat (J/mol.C) 67.2Surface pressure (kPa) 101

Surface temperature (C) 15

Relative Permeability Endpoints for Reservoir:

Irreducible water saturation0.2Irreducible oil saturation for oil/water system (Soirw) 0.1Residual oil saturation for oil/water system 0.1Residual oil saturation for oil/gas system0.02Critical gas saturation0.1Oil relative permeability at irreducible water saturation0.75Gas relative permeability at connate liquid0.85Gas relative permeability at 1Soirw 0.6Capillary Pressure Endpoints for Reservoir:

Maximum value of water/oil capillary pressure (kPa) 1.0Maximum value of gas/oil capillary pressure (kPa)2.0

a)

Slimholes

b)

Slimholes

31 m

42.5 m

743 m

IJK

Shale layer Shale layer

Fig. 7Homogeneous sand with a continuous shale layer (a)above the injector and producer and (b) between the injectorand producer.

I

J

K

Half-symmetry used

Shale lense

31 m

42.5 m

65 m

Fig. 8Homogeneous sand with shale lenses.


of shale lenses have shown behavior similar to that observed inthis project.

Heterogeneous Sand With No Shale (Fig. 9). In contrast toFig. 8, the model here is for a full reservoir (i.e., symmetry wasnot used). The heterogeneity of the system is visually apparentfrom viewing the three faces visible in Fig. 9 and also fromFig. 10, which shows the porosity distribution in the second layerfrom the bottom (K 2) and the location of the horizontal slim-holes from the producer that were used in one of the simulationsdiscussed later. The arithmetic mean porosity and its standarddeviation were 32.95 and 0.82%, respectively. The correspondingvalues for the horizontal permeability were 6.39 and 0.80 darcies.The selection of this reservoir type was based on a desire to inves-tigate if vertical slimholes would increase oil production becauseof their ability to increase the average effective vertical perme-ability of a heterogeneous reservoir.

Numerical simulations were performed by use of one of thefollowing two reservoir representations.

Representation 1 (Large Model). The entire reservoir modelwas 743 m long 85 m wide 31 m high with a 738-m-longhorizontal injector and a 731-m-long horizontal producer, whichwas 5 m below the injector and was 1.5 m above the bottom of thereservoir. The lateral spacing between the 25 cm 25 cm slimholeswas 25 m. There were 28 slimholes. The horizontal wells were atone edge of the model (i.e., at J 1). The reservoir dimensions forhalf-symmetry (Figs. 7a, 7b; Fig. 11) were 743 42.5 31 m andwere represented by 253 19 26 gridblocks.

The simulations involved source/sink wells with heaters usedfor SAGD startup. Earlier simulations used discretized wellboresand the PHWELLBORE semianalytical option in STARS thatresulted in numerical issues, excessively long simulation times,and difficulties in lifting the fluid to the surface.

Representation 2 (Small Model). This is a 65-m-long 85-m-wide 31-m-high reservoir (Figs. 12a and 12b). The horizontalinjector was 60-m long, and the horizontal producer was 53 mlong. The latter was 5 m below the injector and 1.5 m above thebottom of the formation. The spacing between slimholes waseither 12 or 24 m. There were 27 19 26 gridblocks for the half-symmetry element (Fig. 12a) in which the well was split along theaxis in the I-direction, and there were 27 37 26 gridblockswhen symmetry was not applied (Fig. 12b). There were four slim-

holes (25 cm 25 cm or 50 cm 50 cm cross section) when theywere 12 m apart and two slimholes when they were 24 m apart.

Typical spacing between SAGD well pairs in field operationsis approximately 100 m; thus, the 85-m width of the models isrealistic in representing the area surrounding one SAGD well pair.The continuous shale layer and shale lenses had a vertical perme-ability of 2.5 1010 darcies, a porosity of 27.7%, an Sw of 0.75,and an SO of 0.25. It should be noted that Fig. 5 was originallydeveloped as a simple schematic to show the concept of slimholesand is not directly related to the reservoir models used in thesimulations.

SAGD Startup. All simulations described here used heaters inboth wells for a 60-day preheat with which production wasobtained in both the top and bottom source/sink wells during thestartup.

SAGD Operating Strategy. For Reservoir Representation 1, themaximum-allowed steam rate for the 738-m-long horizontal injec-tor was specified to be 300 m3 CWE/D (0.41 m3 CWE/m of welllength) in which CWE is the cold-water equivalent of the injectedsteam. For Reservoir Representation 2, the maximum-allowedsteam rate for the 60-m-long horizontal injector was 24 m3 CWE/D (0.40 m3 CWE/m of well length). The minimum-allowedproduction pressure was 1500 kPaa.

Investigation Approach. The investigation approach was asfollows:

Perform 3D numerical simulations for different reservoirconfigurations with operating conditions based on those of thePetroCanada (now Suncor) MacKay River SAGD project.

Apply the SAGD process without slimholes as a baseline forthe different reservoir configurations.

Implement the use of slimholes for the SAGD process. Apply different types of slimhole scenarios both for applica-

tions in which SAGD performance is limited by shale layers or

Full reservoir symmetry not used md

31 m

85 m 65 m

9,0008,5808,1607,7407,3206,9006,4806,0605,6405,2204,800

Fig. 9Heterogeneous reservoir with no shale.

Slimholes

0.3900.3810.3720.3630.3540.3450.3360.3270.3180.3090.300

Porosity

Producer

Fig. 10Horizontal slimholes from producer (plan view atK5 2).

IK

IJ

31 m

743 m

42.5 m

Fig. 11Grid for Reservoir Representation 1 (symmetry used).


lenses and for better SAGD conditions (i.e., 31-m-thick uniformoil sand with high porosity and permeability).

Assess spacing between slimholes (12 or 24 m for ReservoirRepresentation 2 and 25 m for Reservoir Representation 1) andslimhole size (25 cm 25 cm and 50 cm 50 cm cross sections)for slimhole-enhanced SAGD applications.

The preceding investigation was completed and is reported inthis paper.

Results

Reservoir Representation 1 (Large Model). Vertical Slimholesfor a Homogeneous Reservoir. For a homogeneous reservoirwith no shale layer, the vertical slimholes had little effect on bot-tomhole pressure (BHP), oil production, steam injection, SO, andtemperature profiles. The introduction of vertical slimholes leftthe average calendar-day oil rate (CDOR) and the average steam/oil ratio (SOR) for the first 3,094 days (8.5 years) unchanged at148.4 m3/d and 1.98 m3 CWE/m3, respectively.

Vertical Slimholes for a Homogeneous Reservoir With aShale Layer. The results for Reservoir Representation 1 with ashale layer (17.5 m above the bottom of the reservoir and abovethe injector) are summarized in Figs. 13 through 18. In the pres-ence of shale, the 25 cm 25 cm slimholes significantlyimproved oil production at 2,764 days by 53% (Fig. 13) and oilrecovery from 49.3 to 75.2%. With vertical slimholes, betterinjectivity was achieved because of a reduction in injector BHPdue to steam penetrating the shale. The injector and producerBHP started to increase at approximately 500 days when therewere no slimholes and at approximately 1,700 days when vertical

slimholes were used (Fig. 14). The increase in BHP was causedby steam-trap control (10C) that kicked in and increased the pro-ducer backpressure to prevent the production of live steam. Asteam trap of 10C specifies that the well BHP is increased if thetemperature of the produced water is within 10C of the steam-saturation temperature.

As a result of steam penetrating the shale layer (Fig. 15a), oilwas displaced downward from above the shale layer (Fig. 15b).The growth of an initial steam chamber below the shale layer andthen of a secondary steam chamber above the shale layer is appa-rent from Figs. 15a and 15b. This did not occur in the absence ofslimholes, which can be seen from the temperature profiles at 2years (Fig. 16a and 16b). Figs. 17 and 18, respectively, are crosssections of the temperature and SO profiles halfway along the hori-zontal wells and perpendicular to them. They demonstrate the dif-ference in behavior when slimholes are used compared with whenthey are not. In the absence of slimholes, the temperature doeseventually increase above the shale because of conduction, butno oil is produced from this region (Figs. 17 and 18). In contrast,a secondary steam chamber is formed above the shale when slim-holes are used, and substantial oil production is obtained fromthis region. The improvement in oil production created by theslimholes did not occur until after approximately 3 years (1,095days), and for a period before this time there had been even loweroil production than when there were no slimholes. This wasbecause steam was being lost to the oil sand above the shalelayer, thereby reducing oil production from below the shale layer.Production from above the shale layer started at approximately 3or 4 months after the dip in oil production from below the shalelayer.

42.5

m

K/I aspect ratio = J/I aspect ratio = 1

31 m

Horizontal wells at J = 1 for symmetry and at J=19 for no symmetry

IJ

IK

84.5

m

65 mSymmetry

65 mNo Symmetry

Horizontal wells at J = 1 for symmetry and at J=19 for no symmetry

a) b)

Fig. 12Grid for Reservoir Representation 2.

Time, days

Cum

ulat

ive

Oil,

m3

Multiply cumulative production by 2 because symmetry used

Vertical slimholes

No slimholes

Symmetry used multiply values by 2

0 1,000 2,000 3,000 4,000

200,000

150,000

100,000

50,000

Fig. 13Effect of vertical slimholes on oil production for Reser-voir Representation 1 with shale layer.

Time, days

Wel

l BH

P, k

Paa

Vertical slimholes

No slimholes

0 1,000 2,000 3,000 4,000

4,500

4,000

3,500

3,000

2,500

2,000

1,500

1,000

Fig. 14Effect of vertical slimhole on injector and producerBHP for Reservoir Representation 1 with shale layer.


Reservoir Representation 2 (Small Model). Reservoir Repre-sentation 2 was a smaller and simplified version of ReservoirRepresentation 1 and was used to more quickly test the effect ofdifferent slimhole scenarios. For both reservoir representations,the effect of the slimholes was most significant when the reservoirhad a continuous shale layer that was penetrated by the slimholes.Penetration of steam to the oil sand above the shale layer increasedsteam injection by 6.5% (Fig. 19a) and oil production by 67%(Fig. 19b).

A reduction in the steam-injection rate occurred in these simu-lations when the maximum allowed injection pressure (2000kPaa) was reached. This reduction occurred later when verticalslimholes were used because they allowed some steam to enterthe oil sand above the shale layer, thereby delaying breakthroughof steam to the horizontal production well. Again, this wasbecause of the loss of steam to the oil sand above the shale andthe delay in oil being produced from it.

As explained earlier, in the simulations, the slimholes wereconsidered to include some disturbed reservoir outside the actual

drilled hole. This is why the slimhole dimensions are quite large(i.e., 25 cm 25 cm or 50 cm 50 cm), and they are consideredin the simulations to be porous media. It is interesting to examinehow the simulations predict fluid-flow behavior through the slim-holes. For example, consider the gas and oil velocity vectors (Fig.20) at 360 days. They show the upward motion of gas and thedownward flow of oil through the vertical slimholes. Fig. 21 dem-onstrates the change in gas and oil velocity with time in a slim-hole block in the shale layer. In this figure, downward velocity ispositive. The maximum gas velocity through the slimhole wasapproximately 3,000 m/d (208 cm/min) upward, and the maxi-mum oil velocity was approximately 20 m/d (1.4 cm/min) down-ward. The oil velocity downward and the gas velocity upward in aslimhole block in the shale layer generally increased or decreasedtogether because the oil above the shale layer was replaced bygas. The use of slimholes allowed the release of the excess pres-sure above the shale layer, which was initially caused by conduc-tive heating from below the shale layer.

The mechanism by which steam penetrates to the oil sandabove the shale layer and creates a secondary steam chamberresulting in substantially more oil production is as follows:

1. The pressure builds up in the oil sand above the shale layerbecause of conductive heating.

2. Oil starts to be produced (through the slimholes) from abovethe shale layer, and the pressure there falls simultaneously.

3. Steam starts to penetrate (through the slimholes) to theupper oil sand, and a secondary steam chamber is formed.

4. Steam goes to the top of the upper layer and displaces oildownward, thereby increasing the oil velocity.

The preceding steps are indicated in Fig. 21, and the secondarysteam chamber is shown in Fig. 22.

Effect of Spacing Between Vertical Slimholes Through ShaleLayer. For a homogeneous reservoir with a shale layer, oil recov-ery after 10 years was improved by 69.5% by the use of 25 cm 25 cm vertical slimholes spaced 12 m apart and by 61.5% if theywere 24 m apart (Table 5). The SOR values for the baseline (noslimholes), 12-m spacing for 25 25 cm slimholes, and 24-m

Temperature Oil Saturation

C

60 days

1 year

2 years

3 years

4 years

5 years

Temperature indicative of steam penetrating through shale layer

60 days

1 year

2 years

3 years

4 years

5 years

Oil sand depletion indicative of steam penetration above shale

b)a)

210

1.000.950.900.850.800.750.700.650.600.550.500.450.400.350.300.250.200.150.100.050.00

189

168

147

126

105

84

63

42

21

0

Fig. 15The (a) temperature and (b) SO profiles for Reservoir Representation 1 with shale when vertical slimholes were used.

Indicative of steam penetrating through shale layer

31 m

b)

a)

C210189168147126105846342210

Fig. 16Temperature profiles at 2 years for Reservoir Repre-sentation 1 with shale for (a) slimholes and (b) no slimholes.


spacing for 25-cm2 slimholes were, respectively, 3.40, 2.13, and2.25 m3 CWE/m3. Average CDOR values obtained were 5.6, 9.4,and 9.0 m3/d for the 53-m length of the production well. Theincreased oil production (Fig. 23) was caused by the recovery ofpreviously inaccessible oil from above the shale layer.

Effect of Size of Vertical Slimholes Through ContinuousShale Layer Above the Horizontal Well Pair. When the continu-ous shale layer was above the injector, increasing the size of theslimhole cross section from 25 cm 25 cm to 50 cm 50 cmhad little, if any, effect on oil production for 12-m slimhole spac-ing (Fig. 23). In contrast, increasing the slimhole size had a signif-icant effect on 24-m slimhole spacing, in which it increased the

average CDOR over 10 years by 17% from 9.0 to 10.5 m3/d andreduced the SOR by 16% from 2.25 to 1.90 m3 CWE/m3.

Effect of Vertical Slimholes When There Was a Shale LayerBetween the Injector and Producer. When there was a shalelayer between the injector and producer, oil production was negli-gible if vertical slimholes were not used, even though the oil sandbeneath the shale was heated by conduction.

Smaller spacing was important even for large slimholes whenthere was a shale layer midway between the injector and producer.The wells were 10 m apart. The use of slimholes resulted in sig-nificant oil production (Figs. 24 and 25) in the later SAGD stageespecially for 50 cm 50 cm slimholes, but the oil rate was still

SlimholesNo slimholes

0 days

60 days

1 year

2 years

3 years

4 years

C210189168147126105846342210

Fig. 17Temperature JK profiles at I5127 (midpoint along the horizontal wells) for Reservoir Representation 1 with shale.

0 days

60 days

1 year

2 years

3 years

4 years

SlimholesNo slimholes

1.000.950.900.850.800.750.700.650.600.550.500.450.400.350.300.250.200.150.100.050.00

Fig. 18SO JK profiles at I5 127 (midpoint of horizontal wells) for Reservoir Representation 1 with shale.


a)

Time, days

Cum

ula

tive

Stea

m,

m3

CWE

Vertical slimholes

No slimholes

Maximum pressure of 2 MPaa reached

Symmetry not used

b)

Symmetry not used

No slimholes

Vertical slimholes

Time, days

Cum

ulat

ive

Oil,

m

3

Symmetry not used

Vertical slimholes

No slimholes

00

1,000 2,000 3,000 4,000 0 1,000 2,000 3,000 4,000

40,000 20,000

15,000

10,000

5,000

30,000

20,000

10,000

Fig. 19Effect of slimholes on (a) cumulative steam injected and (b) oil produced for Reservoir Representation 2 with a continu-ous shale layer.

Grid block where slimhole penetrates

shale

Slimhole

m/dm/d

Gas Velocity

Positive Velocity is down

0.00.30.50.81.11.41.72.02.32.52.8

2992692382071771461158554237

Injector Layer

Shale Layer

Oil Velocity

Fig. 20Gas and oil velocity vectors at 360 days for Reservoir Representation 2 with a continuous shale layer.

Oil sand above shale

Oil velocity

Gas velocity

Injector BHP

5,000

4,000

3,000

3,000

3,000

2,000

2,000

2,500

1,5001,000

1,000

5000

3,000

2,000

2,000

1,000

1,0000

0

0

30

20

10

10

0

Pres

su

re (k

Paa)

1

2

3

4

Pre-heat

Oil

Velo

city

(m/d)

Time, days

Fig. 21Steps in fluid penetration through shale layer.

Gas

Vel

oci

ty (m

/d)

Slimhole X-section area = 25 cm x 25 cm

193173152131111906949288

Secondary steam chamber

C

Temperature at 1,246 days

214

Fig. 22Formation of secondary steam chamber above shalelayer.

TABLE 5EFFECT OF SLIMHOLE SPACING AND SIZE FOR CONTINUOUS SHALE LAYER

ABOVEWELL PAIR (RESERVOIR REPRESENTATION 2)

Slimhole

Size

Slimhole

Spacing

Average SOR

(m3 CWE/m3)

% Oil Recovery

after 10 Years

No slimholes 3.40 46.5

Vertical slimholes 25 cm 25 cm 12 m 2.13 78.8Vertical slimholes 25 cm 25 cm 24 m 2.25 75.1Vertical slimholes 50 cm 50 cm 12 m 2.11 79.6Vertical slimholes 50 cm 50 cm 24 m 1.90 88.1


low during the early SAGD stage. After the steam broke throughthe shale through the slimholes, the oil rate increased dramati-cally. The initial low oil rate occurred for 4 to 5 years.

Increasing both the SAGD well-pair spacing from 5 to 10 mand the vertical slimhole size from 25 cm 25 cm to 50 cm 50cm resulted in earlier and higher oil-production rates. Oil produc-tion was higher for 12-m vertical slimhole spacing than for 24-mspacing (Table 6).

Effect of Vertical Slimholes for Low Vertical Permeabilityand No Shale Layer. Even in the absence of shale layers, slim-holes may have applicability if the vertical-to-horizontal perme-ability ratio (kv/kh) is low. With a vertical permeability of 640 md,kv/kh 0.1, and vertical slimholes (25 cm 25 cm in size and 12m apart) initially resulted in greater steam injection (Fig. 26a),which led to greater oil production (Fig. 26b). However, after arun time of 10 years, the oil production was less than 2% greaterthan that obtained without slimholes.

Effect of Vertical Slimholes for Homogeneous ReservoirWith Shale Lenses. The effect of vertical slimholes was eval-uated for a reservoir with uniform sand apart from four shalelenses distributed in four different layers (5, 12, 18, and 23)(Fig. 8). The shale lenses accounted for 16% of Layer 5, 9% ofLayer 12, 36% of Layer 18, and 7% of Layer 23. The shale lensesin Layers 5 and 12 were 1 m thick, and in Layers 18 and 23 theywere 1.5 m thick. The shale lenses had the same properties as theshale layer specified in Table 4. The simulations indicated thatvertical slimholes (spaced either 12 or 24 m apart) had little effecton injected steam (Fig. 27a), oil production (Fig. 27b). Shalelenses effectively act as baffles and slow down fluid flow, effec-tively creating a reduced vertical permeability, and in this casethe effective permeability in the vertical direction was still highenough that slimholes had little effect.

Effect of Horizontal Slimholes From Producer. The effectof horizontal slimholes emanating from the producer at 12-mintervals was examined for a heterogeneous reservoir with a ran-domly generated log-normal distribution of oil-sand porosity

Symmetry used - multiply values by 2

and 0.5 m in size

VSH 24 m in Spacing and 0.25 m in size



50 cm x 50 cm 12 m spacing 50 cm x 50 cm

Time, days

Cum

ulat

ive

Oil,

m3

25 cm x 25 cm 12 m spacing

24 m spacing

25 cm x 25 cm24 m spacing


16,579

11,579

6,579

1,5790 1,000 2,000 3,000 4,000

Fig. 23Effect of slimhole spacing and slimhole size on cumu-lative oil production for shale located above injector andproducer.

Symmetry used - multiply values by 2

SAGD Well 10m apart with VSH Spacing&25 cm x 25 cm in H 24 m in Spacing&25 cm x 25 cm

SAGD Wells 5 m Apart, VSH 12 m in Spacing & 25 cm x 25 cm in Size

SAGD Wells 5 m Apart, VSH 24 m in Spacing & 25 cm x 25 cm in Size

Time, days

Cum

ulat

ive

Oil,

m3

0 423 1,423 2,423 3,423

200

0

400

600

800

1,000

1,200

1,400




Fig. 24Cumulative oil production for 25-cm2 slimholes withwellbores 5 m apart for shale located between injector andproducer.

SAGD Wells 10 m Apart, VSH 12 m in Spacing & 0.5 m in Size

SAGD Wells 10 m Apart, VSH 24 m in Spacing & 0.5 m in Size C

umul

ativ

e O

il, m

3

Time, date




20,000

15,000

10,000

5,000

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 20180

Fig. 25Cumulative oil production for 50-cm2 slimholes withwellbores 10 m apart for shale located between injector andproducer.

TABLE 6SIMULATION RESULTS FOR SHALE LAYER BETWEEN INJECTOR AND PRODUCER

WELL PAIR (RESERVOIR REPRESENTATION 2)

Reservoir Representation 2:

Shale Between the Wellbores

Average

CDOR (m3/d)

Average SOR

(m3 CWE/m3)

% Oil Recovery

after 10 Years

Injector and producer 5 m apart

No slimholes 0.00 0.73 0.2

Vertical slimholes

12-m spacing25 cm 25 cm size 7.2 1.99 60.524-m spacing25 cm 25 cm size 4.9 2.65 40.9

Injector and producer 10 m apart

No slimholes 0.0 0.81 0.1

Vertical slimholes

12-m spacing25 cm 25 cm size 0.0 11.27 0.224-m spacing25 cm 25 cm size 0.0 11.57 0.212-m spacing50 cm 50 cm size 8.0 2.05 66.924-m spacing50 cm 50 cm size 7.2 2.07 60.1


[average 0.33 and a standard deviation of ln (porosity) 0.02].Similarly, average oil-sand permeability was 6.4 darcies, and thestandard deviation of its natural log was 0.1. The slimholes hadessentially no effect on oil production when their assigned abso-lute permeability was 1,000 darcies but did marginally increaseoil production by 2.4% when their absolute permeability wasincreased to 100,000 darcies (Fig. 28).

At the level of the production well, horizontal flow in theJ-direction (perpendicular to the horizontal wells) was much moreuniform in the absence of horizontal slimholes (Figs. 29a and29b). When slimholes were used, most of the lateral flow to the

producer was through the slimholes. The fact that the slimholeshad little effect on oil production, despite the difference theycaused in lateral flow to the producer, indicates that most of the oilflow of interest was from the layers above the producer.

The effectiveness of horizontal slimholes from the producerwill depend on the balance between vertical and horizontal per-meability. Thus, if the vertical permeability is much lower thanthe horizontal permeability, then even increasing the effectivehorizontal permeability with many horizontal slimholes will havea limited effect on a drainage process.

Conclusions

On the basis of 3D field-scale numerical simulations we come tothe following conclusions: Use of vertical slimholes is an effective technology for SAGD

applications in reservoirs with a continuous shale layer. Theyimprove SAGD performance by recovering previously inacces-sible oil from above the shale layer in which a secondary steamchamber is formed. After approximately 3 years of injection,the positive effect of vertical slimholes came into play, and oilproduction became substantially greater compared with whenthere were no slimholes.

Slimhole size had little effect at 12-m spacing but had aneffect at 24-m spacing. The use of 25 cm 25 cm verticalslimholes with 12-m slimhole spacing resulted in a significantimprovement in SAGD performance. Increasing the slimholespacing from 12 to 24 m reduced the effectiveness of theslimholes.

At 12-m spacing, 25 cm 25 cm and 50 cm 50 cm verticalslimholes had a similar positive effect on SAGD performance.However, the effectiveness of the larger vertical slimholes was

Vertic

al slim

holes

No

slimho

lesVertic

al slim

holes

No

slimho

les


Time, days

Cum

ulat

ive

Stea

m, m

3 CW

E

Time, days

Vertic

al slim

holes

No s

limho

les

Cum

ulat

ive

Oil,

m3


40,000

30,000

20,000

10,000

20,000

15,000

10,000

5,000

00

01,000 2,000 3,000 4,000 0 1,000 2,000 3,000 4,000

a) b)

Fig. 26Effect of slimholes on (a) cumulative steam injected and (b) oil produced for Reservoir Representation 2 with an oil-sandvertical permeability of 640 md.

Time (days)

Cum

ulat

ive

Stea

m, m

3 CW

E No slimholes 12 m slimhole spacing 24 m slimhole spacing


Time (days)

Cum

ulat

ive

Oil,

m3

No slimholes 12 m slimhole spacing 24 m slimhole spacing


30,000

40,000

20,000

10,000

00 1,000 2,000 3,000 4,000 0 1,000 2,000 3,000 4,000

20,000

15,000

10,000

5,000

0

a) b)

Fig. 27(a) Cumulative steam injected and (b) cumulative oil production for Reservoir Representation 2 with shale lenses.

Horizontal slimholes from producer (100,000 Darcy)

Time (days)

Cum

ulat

ive

Oil,

m3

100,000 darcy horizontal slimholes

Symmetry not used

40,000

30,000

20,000

10,000

00 1,000 2,000 3,000 4,000

Fig. 28Effect of horizontal slimholes from producer on cumu-lative oil production.


maintained even when the slimhole spacing was increased from12 to 24 m.

For 24-m vertical slimhole spacing, increasing the slimhole sizefrom 25 cm 25 cm to 50 cm 50 cm resulted in a 17%increase in average CDOR over 10 years and a 16% decrease inaverage SOR.

When there was a shale layer between the injector and pro-ducer, minimal oil production was obtained in the absence ofvertical slimholes. This was despite the fact that the oil sandbeneath the shale layer was heated by conduction. The use ofvertical slimholes resulted in some oil production; the initial oilrate was still low but increased to a relatively high value for 50cm 50 cm slimholes after approximately 3 years for 12-mspacing and after approximately 4 years for 24-m spacing.

Vertical slimholes are a potential solution for SAGD operationsinvolving lower-quality oil sand or multiple layers of thin pay,particularly in which the oil sand is at a shallow depth.

The mechanism by which the steam penetrates a shale layer andforms a secondary steam chamber is as follows:* Pressure initially builds up above the shale layer because of

conduction and then drives the bitumen down through theslimholes. This effect will be reduced but is still significantif the reservoir is not confined as it was in the simulationsdiscussed here. A buildup of pressure in this oil sand couldresult in significant geomechanics effects.

* Steam moves upward and oil downward in the slimholesthrough the shale layer.

* The steam induces a secondary steam chamber to formabove the shale layer.

Vertical slimholes had a negligible effect on a reservoir withshale lenses (baffles) and a homogeneous oil sand (kv/kh testedfrom 0.1 to 1).

Horizontal slimholes emanating from the producer had littleeffect on SAGD performance even when the absolute perme-ability of the slimholes was increased from 1,000 to 100,000darcies.

Nomenclature

kv1, kv2, kv3, kv4, kv5 coefficients for specific gaseskv/kh vertical to horizontal permeability ratio

P pressure, kPaSO oil saturationSw water saturationT temperature, Kxi equilibrium fraction of i in oil phase

xieqm oil phaseyi mole fraction of i in gas phase

llive oil viscosity of the oil phaseli pseudoviscosity of component i

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a) Slimhole

Oil sand

m/d11.9

9.4 7.0 4.5 2.0

0.4 2.9 5.3 7.8 10.212.7

Producer

Producer

Fig. 29Oil velocity vectors and oil velocity in J-direction pro-file at 315 days at the level of the producer for Reservoir Repre-sentation 2 without shale (a) for no slimholes and (b) forhorizontal slimholes from producer.


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Jeannine Chang is a Reservoir Simulation Specialist at DevonCanada Corporation, and before that she was at AITF. Herwork has primarily focused on reservoir simulation and labora-tory experiments of enhanced-oil-recovery (EOR) technolo-gies, including cyclic injection processes (solvent, steam,steam/solvent, and steam/air), SAGD, cold heavy-oil produc-tion with sand and vapour extraction process. Before AITF,Chang was an environmental consultant focusing on environ-mental assessments and petroleum-contaminant remediation.

John Ivory is the Heavy Oil and Oil Sands Subsurface PortfolioManager at AITF in the areas of EOR (primarily solvent, steam,steam/solvent, and in-situ-combustion processes) and leadsAITFs Reservoir Simulation Group. He has extensive expertisein both designing experiments and performing numerical simu-lations related to enhanced heavy-oil and bitumen recoveryprocesses. Ivory also has investigated gas separation/purifica-tion by use of membranes, adsorption, and absorptiontechnologies.

Cathal Tunney is responsible for technology transfer in AITFsPetroleum Division. He has contributed to the developmentof several concepts for the preconditioning of oil-sand reser-voirs to improve the performance of in-situ gravity-drainageprocesses and to investigate novel absorption processes forthe separation of CO2. Before joining AITF, Tunney worked in arange of new-product-development projects and businessstartups, including microwave-sintered ceramics, fuel cells,burn-wound dressings, and shape-memory alloy components.


spe-148803-pa (numerical simulation of steam-assisted gravity drainage with vertical slimholes)

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