PETSOC-2009-175

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PAPER 2009-175

Cyclic Steam-Solvent Stimulation

Using Horizontal Wells J. CHANG, J. IVORY, R.S.V. RAJAN

Alberta Research Council

This paper is accepted for the Proceedings of the Canadian International Petroleum Conference (CIPC) 2009, Calgary, Alberta, Canada, 16‐18 June 2009. This paper will be considered for publication in Petroleum Society journals. Publication rights are reserved. This is a pre‐print and subject to correction.

Abstract This paper summarizes horizontal well cyclic steam stimulation with solvent (HW-CSS-S) process strategies that were examined for a Cold Lake type reservoir. The strategies included co-injection of n-hexane (C6H14) and steam, injection of C6H14 prior to steam-only injection, and injection of steam and C6H14 in alternate series of cycles. 2-D and 3-D single well and two-well simulations were preformed using the CMG STARS thermal simulator. The simulations used the Beattie-Boberg model to represent dilation and recompaction. The effects of solvent concentration, soak period, maximum allowed liquid production rate, and pay thickness on the HW-CSS-S process were considered. The performance of horizontal and slant wells were compared. The simulation results indicated:

• The most promising injection strategy was a combination of steam-only, steam-C6H14, and C6H14-only injection cycles. However, the less complex co-injection of 5 mole% C6H14 in steam also performed well.

• For steam-C6H14 co-injection, oil production increased significantly with C6H14 concentration but the increase was marginal above 5 mole% C6H14 in the steam.

• Increasing the maximum allowed liquid production rate from 1 to 5 m3/d/m of well length had a major impact on HW-CSS-S behaviour. The oil rate had a maximum value when the allowed liquid production

rate was 4 m3/d/m of well length and the cumulative steam oil ratio (CSOR) increased with the allowed liquid production rate.

• An increase in pay thickness resulted in increased oil production and a lower steam-oil ratio, but the net solvent to oil ratio was greater due to a reduction in solvent recovery.

• Water injection at an infill well increased the reservoir pressure and reduced both the amount of steam injected and oil production.

• An infill horizontal producer midway between two cyclic horizontal wells (spaced 402 m apart) increased the oil rate by 31%, reduced the CSOR by 9%, and decreased the net C6H14 to oil ratio by a factor of 3. The closer the infill producer was to the bottom of the pay, the better was its performance.

• For a uniform formation, horizontal wells performed better than slant wells.

It is recommended that, when injecting steam and solvent separately in a particular cycle, that the solvent before the steam rather than after it. Injection of steam before the solvent increases the reservoir temperature and reduces solvent solubility. Although injecting solvent before steam in the same cycle may temporarily result in increased solvent retention in the reservoir, solvent may be recovered by steam-only or steam CH4 injection in subsequent cycles.

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Introduction

This paper summarizes simulations that were performed todevelop steam-solvent injection strategies focused on horizontalwell applications and to estimate the effect on the process of anumber of reservoir and fluid parameters. Solvents and steamwhen used together in a cyclic mode provide synergistic effectssuch as reduced viscosity, solution gas drive due to methaneand hexane dissolution, improved gravity drainage, and muchfaster diffusion of solvent as the reservoir becomes heated bysteam. Horizontal wells improve oil recovery as compared toCSS with vertical wells since they improve contact with thereservoir and more effectively utilize gravity drainage.

The strategies reported on in this paper include co-injection ofsolvent (C6H14, condensate, or CH4), injection of solventsbefore or after steam-injection in the same cycle, and alternateCSS and cyclic solvent injection (CSI) cycles. These strategieswere performed in order to develop a cyclic process withhorizontal wells that can reduce water use and energyconsumption while improving oil production.

The simulations used the Beattie-Boberg model (Beattie et al.,1991) in STARS for dilation and re-compaction. The Ito SandDeformation Model (Ito (1984), Ito and Hirata (1994), Ito et al.(1992), and Ito et al. (1993) was also used for CSS simulationsand the results will be presented in a subsequent paper.

CSS with vertical wells has been applied on a commercial scalefor many years by petroleum producers including Imperial Oilin Cold Lake (Clearwater), CNRL in Cold Lake (Primrose Lakeand Wolf Lake, Clearwater), Shell Canada in Peace River,PDVSA (Bachaquero Field, Lake Maracaibo, Venezuela),Chevron-Texaco (California). Horizontal well CSS is alsobeing applied by some producers. Shell tested CSS at PeaceRiver using horizontal laterals drilled into the reservoir from themain boreholes. The average pay is 25 m and the viscosity ofthe 8 API bitumen at reservoir temperature (17 C) andpressure (3.7 MPa) is 200,000 mPa.s (Goobie and Chang). Thesandstone reservoir is at a depth of about 600 m (McGillvray).

Berry Petroleum placed horizontal wells close to the bottom ofthe 13 API oil reservoir (McKay et al., 2003) in the SouthMidway-Sunset field. The horizontal wells were subjected toCSS (5,000 m3 CWE of steam) before being used as producers.The wells were up to 500 m in length and oil productiongenerally increased linearly with well length.

In Venezuela, horizontal wells were stimulated with steam atBachaquero (Lake Maracaibo) (Cosentino et al.). The oildensity is 14 API and the reservoir pressure is 4,800 kPa. Theporosity is between 30 and 40% and the permeability between0.5 and 2 Darcy. Solution gas drive and compaction were themost important production mechanisms.

Courtnage and Adegbesan (1992) examined vertical well CSSwith some horizontal infill wells as producers. The horizontalwells enhanced gravity drainage and provided more flow pathsfor steam to enter the reservoir from the vertical wells. Much ofthe early oil production was caused by the vertical wells alonewhile the horizontal well improves later performance.

A typical CSS cycle consists of steam injection (~10% of cycle),soak (~5% of cycle), and production (85% of cycle). Steamrates in vertical wells can be about 200 - 300 m3/d CWE withabout 8,000 - 10,000 m3 injected in early cycles. The amountof steam injected is increased in subsequent cycles.

Important CSS mechanisms include formation dilation and re-compaction, possibly solution-gas drive created by theformation of a foamy oil zone between hot and cold regions,fluid expansion, gravity drainage in later cycles, and theformation of emulsions. As pressure drive mechanisms decline,gravity drainage becomes important due to the large steamchambers formed. Gravity drainage is efficient but is slow andoil rates decline in later cycles. Dilation and re-compaction inCold Lake result in high steam injection rates and aneconomical CSS process in Cold Lake. Oil production inAthabasca reservoirs has been limited by poor re-compaction.

In addition to compaction drive, solution gas drive, steamflashing, and gravity drainage, Batycky et al., 1997, consideredthe bitumen mobilization processes of foaming andemulsification to be important, particularly during later cycles.They considered that much of the effectiveness of CSS was dueto the formation of a foamy oil zone (less than 10 m thick),which lies between the hot and cold reservoir zones. Rapid gasexsolution in this zone during cold production, when thepressure falls below the bubble point pressure, causes foamformation, which impedes gas and water flow. The foamy oilzone allows an efficient solution gas drive to displace bitumen.The heated zone near the well acts as a conduit for the displacedbitumen. As the colder reservoir bordering the heated zonestarts to dilate and re-compact and gas starts to exsolve from theoil, the oil ahead of it is displaced towards the well bycompaction and solution gas drive.

The geomechanics failure of a production formation duringsteaming increases well interactions (Courtnage and Adegbesan,1992). Considerable inter-well communication occurs duringCSS operations at Cold Lake, because injectivity is achievedthrough fracturing the formation (Vittoratos et al, 1990).Initially, this interaction is good with wells on injectionproviding pressure support to adjacent wells. Eventually, inter-well communication limits injection pressures as steam is lostto adjacent steam chambers. Consequently, less dilation occursduring injection and re-compaction is of reduced importanceduring production. It also can result in watering out of a wellon production through steam injected in another communicatingwell. To minimize the negative aspects of inter-wellcommunication, wells have been steamed sequentially with50% overlap in injection times between adjacent rows.

Vittoratos (1991) stated that most of the bitumen in early cyclesis recovered as water in oil emulsion. The emulsion viscosity isgreater than the oil viscosity (Vittoratos, 1991). This is morethan compensated by the increased oil saturation (and thereforeincreased oil relative permeability) due to oil phase swellingresulting from the water in the emulsion. In later cycles, freewater around the well competes with the emulsion flow andbitumen production decreases.

The use of solvents with CSS using vertical wells has beendemonstrated (Ivory, 1985; Stone and Ivory, 1987) to result inincreased oil recovery as a result primarily of the synergisticeffects of steam and solvent in reducing oil viscosity. Inaddition, a solution gas drive can occur during production as thesolvent comes out of solution.

Hybrid steam-solvent processes have been developed at ARCfor SAGD operations as a method of recovering heavy oil andbitumen from viscous reservoirs. The processes are based onthe injection of steam with solvent in a SAGD well pairconfiguration. A range of steam-solvent injection fluids have

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been investigated ranging from a low concentration of a heavysolvent in the steam as in ES-SAGD (Nasr, 2003) to a highconcentration of a light solvent (e.g. propane or butane) as inthe thermal solvent hybrid process (Frauenfeld et al., 2005 andIvory et a., 2007).

In the steam alternating solvent process (SAS), which wasdeveloped at ARC, steam and solvent are injected alternatelyusing a SAGD well configuration (Zhao, 2004 and Zhao et al.,2004). The basic idea of SAS, is to replace a large amount ofthe steam with solvent, realizing that much of the solvent can berecycled. The solvent dew point should be between the initialreservoir temperature and the steam temperature. A blow-downis used to recover solvent from the reservoir.

Encana applied steam-solvent at Christina Lake and at TuckerLake (Gupta et al., 2003 and 2005, Gupta and Gittins, 2005). Asolvent aided process (SAP) pilot test (2001-2002) resulted in50% more oil production. The CSOR for the SAP was 1.4when butane was injected as compared to 2 for SAGD

In the LASER (liquid addition to steam for enhancing recovery)process, diluent is co-injected with steam (about 6 volume%)during CSS (Leaute, 2002). This process was field tested byImperial Oil (Leaute and Carey, 2005) at its Cold Lakeoperations where diluent (C5+ condensate) was injected into 8vertical wells during CSS Cycle 7. The purpose of the pilotwas to determine the reduction in CSOR and solvent recovery.The steam to incremental oil ratio was 0.1 and 80% of theinjected solvent was recovered, a large fraction of this was inthe vent gas. Dynamic solvent refluxing was hypothesized asan important mechanism in the process. The recovered diluentcomposition was close to that of the injected diluent.

Numerical Simulations

Numerical simulations were performed using the CMG STARS200610 simulator. The numerical simulations involved thefollowing models:

2-D single horizontal well model for faster simulations

2-D multiple horizontal wells (2 cyclic horizontal wellswith/without an infill horizontal well) to allow for inter-well interference

3-D single horizontal well for looking at the CSS-HWprocess in 3 dimensions

3-D multiple horizontal wells (2 cyclic horizontalwells) to allow for inter-well interference

The initial reservoir properties were as follows:

Table 1: Initial Reservoir Properties

Reservoir depth (m) 450

Porosity (%) 35

Horizontal permeability (Darcy) 1.5

Vertical permeability (Darcy) 0.45

Reservoir temperature (C) 13

Reservoir pressure (MPaa) 3.1

Water saturation 0.3

Oil saturation (So) 0.7

Gas-oil ratio (GOR) (std m3/m3) 9.8

Other properties used in the simulations are in Appendix B. Inthe simulations, the maximum allowed injection pressure was10 MPaa and the minimum allowed production pressure was150 kPaa.

The 2D single HW-CSS-S simulations were concentrated ondeveloping an effective operation process strategy. More than17 different strategies were evaluated for injecting C6H14 andsteam in order to optimize the usage of steam and solvent.They included co-injection of 5 mole% C6H14 in steam,injection of C6H14 prior to steam-only injection, and injection ofsteam and C6H14 in alternate groups of cycles. C6H14 wasselected as the solvent in the developed strategies because itsvaporization thermodynamic behavior is similar to that of steami.e. it condenses during injection and vaporizes duringproduction at a similar temperature to steam as compared toother solvents. Although C6H14 has slightly lower saturationtemperature at lower pressure than that of water, with highpressure CSS-S its saturation temperature and pressure arecomparable (Figure 1).

The process strategies were based on an objective of applyinghorizontal well technology combined with steam and solventinjection to maximize heavy oil recovery, increase calendar dayoil rate (CDOR), reduce CSOR, nett solvent-oil ratio, andsolvent retention, and etc. The goals were achieved byalternating the duration of injection, soak, and productionperiods and sequences. The injection strategies used and theresults obtained are summarized in Tables C-1 and C-2 inAppendix C.

In addition to developing HW-CSS strategies, the effects of thefollowing were investigated in 2D multi-well and 3Dsimulations:

Pay thickness (11.6 m, 14 m, or 26 m)

Well spacing (180 m and 402 m)

Use of horizontal and slant wells

Injection of different solvents in addition to steam

- Solvents investigated included C6H14, CH4, andgas condensate.

Injection of water in an infill horizontal well

Infill horizontal producer

In all of the simulations, dilation and re-compaction weresimulated based on the Beattie-Boberg model (Figure 2), whichis described in some detail in Appendix A (Beattie et al., 1991).

2-D Numerical Simulations

The 2-D field scale simulations considered 1 m length of ahorizontal well. Oil production was multiplied by 500 in orderto represent the production from a 500 m long well.

Two different reservoir grid systems were used:

Single horizontal well system, which had a 49 x 1 x 28grid block system (representing 402 m wide, 1 m long,and 26 m high portion of a reservoir Figure 3). Theoriginal oil in place was 2,561 m3.

Multiple well system, which had a 98 x 1 x 28 gridblock system (Figure 4) and was used to represent 1 mlength of the horizontal well in the reservoir region of

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interest (804 m wide, 1 m long, and either 11.6, 14, or26 m high).

Process Strategies

Based on their CDOR, CSOR, net solvent to oil ratio, andsolvent retention, the three "best" injection strategies weredetermined in 2-D single well simulations to be Strategies 14, 1,and 10. Their CDOR, CSOR, net solvent-oil ratio and solventretention values are summarized in Table 2 along with those forsteam-only injection (Strategy 2).

STRATEGY 14

Strategy 14 involved steam-C6H14 co-injection cycles, C6H14-only injection cycles, and finished with 2 steam-only cycles forsolvent recovery. It involved the following 24 cycles insequence over 3,900 days (10.7 years). Details of the strategyare described in Table C-2 and are shown schematically as:

• 3 CSS steam-C6H14 co-injection (5 mole% C6H14)cycles

• 3 C6H14-only injection cycles (cyclic solvent injection,CSI)

• 3 CSS steam-C6H14 cycles co-injection cycles• 5 CSI cycles• 3 CSS steam-C6H14 co-injection cycles• 5 CSI cycles• 2 CSS steam-only injection cycles to recover C6H14

from the reservoir

Compared to steam-only injection (Strategy 2), this strategyincreased oil production from 47.3 to 59.0 m3/d and reduced theCSOR from 7.50 to 3.77 m3 CWE/m3 but at the expense ofleaving C6H14 in the reservoir (0.62 liquid m3 C6H14/m

3 oilproduced) (Table 2).

STRATEGY 1

Strategy 1 involved co-injection of C6H14 and steam (5 mole%C6H14). It is similar to the LASER process and previous cyclicsteam-solvent injection research at ARC in that solvent is co-injected with steam. However, it differs in that Strategy 1 wasapplied to horizontal rather than vertical wells. It resulted in aCDOR of 63.5 m3/d, a CSOR of 4.41 m3 CWE/m3, and a netC6H14/oil ratio of 0.78 liquid m3/m3 oil.

The simulation results indicate that Strategy 1 has a relativelyhigh CDOR in compensation for its higher CSOR and netsolvent retention as compared to Strategy 14 (Table 2).

STRATEGY 10

Strategy 10 involved steam-only injection cycles and C6H14-

only injection cycles i.e. it had a number of CSS cyclesalternating with a number of CSI cycles. Details of Strategy 10are provided in Table C-2 and shown schematically as:

This strategy resulted in a relatively lower CDOR of 56.7 m3/d,a CSOR of 5.25 m3 CWE/m3, however, it had a low netC6H14/oil ratio of 0.30 liquid m3/m3 oil (Table2). Net C6H14

retention in the reservoir was about 132 liquid m3 as comparedto 292 liquid m3 in Strategy 14, and 381 liquid m3 in Strategy 1.

Table 2: Comparison Results for "Best" Strategies and CSS

StrategyCDOR(m3/d)

CSOR(m3/m3)

NettSolvent-oil

ratio(liq. m3/m3)

Nett SolventRetention in

Reservoir(liq. m3)

14 59.0 3.77 0.62 292

1 63.5 4.41 0.78 380

10 56.7 5.25 0.30 132

2 47.3 7.50 - -

Evaluation of Strategies 1, 2, 10, and 14

The above three CSS-S strategies resulted in an increase inCDOR (Table 2) and a great reduction in CSOR as compared tothe conventional CSS Strategy 2 (Figure 5).

Strategy 14 had the lowest CSOR as a result of the effective useof steam solvent co-injection and solvent stimulation andimproved CDOR. The idea was to reduce steam usage by thesolvent and recover solvent during the process, in particular byfinishing with 2 steam only cycles. However the steam-onlycycles at the end of process were not effectively in recoveringthe additional C6H14 due to minor oil and gas production duringthese cycles.

Although steam-C6H14 co-injection in every cycle (Strategy 1)injected less C6H14 than did Strategies 10 and 14, it had thegreatest C6H14 retention in the reservoir (Figures 6 and 7). TheC6H14 retained in the reservoir increased with each C6H14-onlyinjection cycle for Strategies 10 and 14. It also increased by asmaller amount during steam-C6H14 co-injection in Strategy 14.

During steam-only or steam-hexane injection cycles, it isnecessary to recover a large amount of water (primarilycondensed steam and some formation water) before significantoil production starts. This delays oil production and increasespumping and separation costs. In contrast, hexane-only cycles

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result in earlier oil production and reduced water usage andwater recycling and treatment costs.

Alternating steam-only and C6H14 injection cycles in Strategy10 resulted in more effective oil recovery from the reservoir ascompared to steam-only CSS. Steam-C6H14 or steam-onlyinjection cycles heat the reservoir and in subsequent C6H14-onlycycles, C6H14 has a much higher diffusion coefficient than atlow temperature and consequently can disperse more quickly inthe reservoir.

CSS-S ENHANCES CSS RECOVERY MECHANISMS

By studying the change in the reservoir and fluid properties atthree different grid block locations for Strategy 14, thepenetration of injected steam and solvent into the reservoir andtheir impact on reservoir properties were investigated. Thecenters of these blocks (A, B, and C in Figure 3) wererespectively 105.875 m, 55.875 m, and 13.375 m laterallydisplaced from the well. They were 14.75 m above the well.

Substantial pressure swings were observed during solvent-onlyinjection cycles and lesser swings were occurred during steam-C6H14 and steam-only cycles as the pressure was still high at theend of production periods of the latter cycles (Figure 8). The highpressure swings result in more effectively utilizing formationdilation and re-compaction, as well as the solution gas drivemechanisms. The temperature at location C fell during solvent-only cycles, but even after C6H14-only injection Cycles 18 to 22in the Strategy 14 still remained above 100 C (Figure 9).

There were only minor changes in the oil and gas saturations atlocations A and B. However, at location C there were significantfluctuations during cycles as the latter was closer to thehorizontal well and was in or near the steam zone (Figures 10and 11). The water saturation at location C was high followingsteam-C6H14 and steam-only injection cycles (Figure 12).

During solvent injection into the reservoir, the solvent molefraction in the oil phase increased as a result of dissolution.Over time, a high C6H14 mole fraction in oil phase was obtainedas compared to the C6H14 mole fraction in gas phase. At theclose to the well location C, the C6H14 mole fraction in the oilreached 1 in some C6H14-only injection cycles. It was minimalfollowing the final two steam-only cycles. At location B, theC6H14 mole fraction in oil did not start to increase until 1,100days and then started to increase with each cycle and was notreduced sufficiently during the steam-only cycles at the end ofthe simulation run. At location A, C6H14 was not observed untilthe steam-only cycles at the end whereby some C6H14 already inthe reservoir was displaced away from the well (Figure 13). Onthe other hand the CH4 in the oil phase decreased with time(Figure 14) to very low values.

The C6H14 mole fraction in oil profile during Strategy 14 isshown at number of times in Figure 15. The profiles indicatethat at the end of the C6H14-only injection period, the C6H14 hadgreater lateral spreading at the bottom than at the top i.e. it hadthe shape of an inverted SAGD chamber. The profiles at theend of injection and the end of production during the steam-only cycles at the end of Strategy 14 display changes in C6H14

dissolved in the oil but overall the final steam-only cycles didnot recover much hexane primarily because most of theproduction in these cycles was water with little oil and gasproduction necessary for recovering C6H14. Thus, it appearsthat a prolonged drawdown is necessary but possibly notsufficient for solvent recovery. It is believed that a steam drive

process or infill wells are more likely to recover C6H14 from thereservoir than a cyclic operation.

With the high temperature region extending further from thewell and the CH4 exsolving accordingly from the oil duringproduction cycles its mole fraction in the gas phase increasedwith time to a maximum before again decreasing as the CH4 inthe oil became diminished (Figure 16). The C6H14 molefraction in the gas fluctuated significantly at location C andsomewhat at location B in later cycles. No C6H14 was observedin the gas phase at location A (Figure 17).

The continuous CH4 gas exsolution enhanced the mechanism ofsolution gas drive for CSS-S. During the C6H14-only injectioncycles, significantly more CH4 exsolved from the oil due to thehigh concentration of C6H14 reducing the CH4 mole fraction inthe gas and consequently its partial pressure. This phenomenonresults in substantially increased CH4 production followingC6H14-only injection periods in both Strategies 10 and 14(Figure 18). This additional gas provided an extra driving forceto produce oil during production cycles. Near the well, the oilbecame depleted of CH4 within the early injection cycles. Thedrop in CH4 mole fraction in the oil during C6H14-only injectionwas apparent at the grid block location B and C in Figure 14.During the steam-only cycles at the end of simulation run, thegas mole fraction was dominated by steam in the swept regionand C6H14 was displaced outwards by the steam front (Figure19).

REDUCTION OF OIL VISCOSITY

Figure 20 shows pressure, temperature, C6H14 mole fraction,and fluid saturation profile at the end of Strategy 14. Theprofiles indicate that a significant portion of the reservoir wasabove 100 C in addition to having a significant amount ofC6H14 in the reservoir at the end of production cycles.Although the temperature declined during C6H14 only cycles,steam-C6H14 co-injection and steam only injection periods wereable to maintain enough energy to retain higher reservoirtemperature and lower oil viscosity at the steam-vapor chamber(Figures 21 and 22). Even though much more oil was producedin Strategy 14, a lower portion of the reservoir had a low oilphase viscosity at the end of this strategy than occurred at theend of Strategy 2. This is discussed in some detail later.

Near the top of the reservoir, high temperature and gassaturation were obtained as a result of steam or steam-C6H14 co-injection. However during C6H14-only cycles, high gassaturation formed near the bottom during production and thenextended to the top and spread laterally (Figure 23). In the zoneof high gas saturation, about 70% of the gas was methane andabout 30% was steam. At the end of Cycles 23 and 24 (steam-only injection), there was essentially no methane, but a highpercentage of steam in this zone. This behavior was becausethe block temperature was essentially the same as the saturationtemperature (calculated from the water partial pressure in thegas although this approach is approximate as methane andhexane have very low solubility in water). The blocktemperature was compared to the saturation temperature basedon the block pressure (Ptotal) and on the partial pressure of waterin the gas phase (Pwater) at three different grid blocks (15-1-26,20-1-26, and 25-1-26) near the top of the reservoir in Strategy14. The block temperature was the same for most of the run as thesaturation temperature based on Pwater (Figures 24, 25 and 26).

The combined impacts of temperature increase and C6H14

dissolution (reduce oil viscosity), and CH4 exsolution (increases

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oil viscosity) resulted in a general reduction in viscosity withtime but with some peaks in oil viscosity at locations B and Cin Strategy 14 (Figure 27). These peaks were a temporaryeffect that occurred while the temperature was still low at theselocations and C6H14 had not yet dissolved in the oil there andwere a result rapid exsolution of dissolved CH4 from the oil asthe high temperature front approached.

The temperature profiles (values between 200 and 320 C)show that as a result of steam-C6H14 co-injection, the reservoirwas hotter during steam-only injection than during steam-C6H14

injection (Figure 28). In Strategy 14, the reservoir was cooledduring C6H14-only injection. In Cycle 6 (C6H14-only) of thisstrategy, none of the reservoir was above 200 C and in Cycles14 and 22, which were also C6H14-only cycles, only a verysmall part of the reservoir was above 200 C. It was decidedthat it would be best to have a number of C6H14-only cycles insequence (rather than having every second cycle a C6H14-onlycycle) to allow the reservoir to partially cool down the reservoirthereby increasing C6H14 solubility.

Figure 29 shows oil phase viscosity profiles (for values between0 and 50 mPa.s) at the end of different soak periods forStrategies 2, 1, and 14. Strategies 2 and 1 had larger volumeswith low viscosity than Strategy 14. The shape of the viscosityprofiles was different in Strategy 14. At the end of the 3, 9, and17th soaks (all of which were steam-C6H14 cycles) and 24th soak(steam-only) the viscosity profiles were similar to those inStrategies 2 and 1. In contrast, the low viscosity profiles weremore bell shaped in the centre with a vertical edge at the outsideat the end of soaks 6, 14, and 22, which involved C6H14-onlyinjection in Strategy 14.

HIGH CDOR WITH SMALL DEPLETION ZONE

The CSS-S process in Strategies 1 and 14, as compared to thesteam-only CSS process in Strategy 2, not only enhanced oilproduction and had lower CSOR, but resulted in a smaller andbetter swept area (Figure 30). Strategy 10 had a greater sweptvolume than Strategies 1 and 14 because it ended with 4 steam-only cycles.

Dead oil saturation is the volume of dead oil in a block dividedby its pore volume. It is calculated from the live oil saturation,oil phase mole fractions, and oil phase component molardensities. It is less than the live oil phase saturation as the latterincludes the volume occupied by dissolved CH4 and C6H14

whereas the dead oil saturation does not. The dead oilsaturation was smaller and confined to a more restricted area inCSS-S. The dead oil saturation profile for steam-C6H14 co-injection in Strategy 1 was similar to that for steam-onlyinjection (Strategy 2) except that: (1) it recovered more oil fromthe depleted region and (2) it displaced more oil away from thedepleted region and the well. Strategies 2 and 10 resulted indead oil recovery from a much greater region, although theyhad the least oil production of the 4 strategies (Table 2).Strategy 14 resulted in a sharp delineation between depletedand un-depleted zones. Thus, it would appear that Strategies 1and 14 would be the most effective for cleaning oil from thereservoir and obtaining a higher ultimate recovery. Just abovethe well for Strategies 10 and 14 there was a narrow region ofvery low dead oil saturation as the live oil phase in this regionwas mostly C6H14.

The injected C6H14 mole fraction in oil is shown at differentstages in Figure 31. The distance scale in the C6H14 molefraction (0.01 to 1) is 90% of that in Figures 28 and 29 in orderto fit the contours on the page. This was necessary as the 0.01C6H14 mole fraction front penetrated further into the reservoirthan the 50 mPa.s viscosity front or the 200 C temperaturefront. The absence of C6H14 directly above the well duringsteam-C6H14 or steam-only injection periods of Strategies 1 and14 clearly show that C6H14 is displaced away from the well bythe steam. The bell and steep shaped profiles in the C6H14 molefraction profiles of Strategies 1 and 14 indicate that C6H14

dissolution in the oil is primarily responsible for the similarshape in the oil viscosity profile (Figure 29).

INCREASED FLOW VELOCITY

The higher CDOR and lower CSOR in Strategies 1 and 14 ascompared to Strategy 2 were because of a greater solution gasdrive and because their steam-solvent vapor chambers and lowviscosity profiles were steeper than that of steam-only vaporchamber, as in Figures 28 and 29. The vertically orientated lowoil viscosity chambers resulted in a greater gravitational impact.In addition, the steep geometric shape allowed fluid to betransported in the shortest distance along the vertical displacingfront of low viscosity oil zone.

In steam-only injection periods, the steam moves to the top andspreads laterally resulting in a low viscosity region that ishigher at the top than the bottom. When solvent is injected, thelow viscosity region is wider at the bottom than the top. InStrategy 14, alternating groups of steam-C6H14 and C6H14-onlycycles were effectively used to combine these 2 viscosityprofiles and obtain a steep vertical orientation of the lowviscosity chamber and the highest flow potential.

C6H14-only cycles have an advantage over steam-only or steam-C6H14 cycles, in that there is much less water near the well atthe end of an injection period. Thus, it is not necessary to pumpback a large amount of condensed water and more rapid initialoil production is obtained. Because of the mechanism, thewells need to be pumped off at a higher rate initially to removeexcess water.

During C6H14-only injection, the oil swelled and the gassaturation became negligible. When the dissolved gas came outof solution, it caused a dissolution gas drive especially at thebeginning of production. A higher flow velocity was achieved.

Figure 32 shows gas and oil velocity vectors at the end ofdifferent injection and production periods of Strategy 14. Atthe end of cycle 6 injection, the flow of injected gas wasprimarily restricted to a narrow band close to the well. In thisband, there was upward flow of oil while outside the band therewas some drainage of oil. At the end of the production periodof hexane-only cycle 6, gas moved upwards in the partially oildepleted region and there was significant downward movementof oil away from the depleted region. At the end of injectionand production periods of cycle 24, gas (primarily steam)continued to rise in the depleted region and spread laterally atthe top. Oil drained and moved toward the well mainly fromoutside the depleted zone.

3-D Field Scale Simulations

Both source-sink type and simple discretized wellbore modelswere used in 3-D simulations, the latter to account for pressure

7

gradient in the well. Reservoir heterogeneities along thedirection of the horizontal well(s) were also considered. Aheterogeneous reservoir was generated using a log-normaldistribution for both the porosity and permeability.

Injection schemes involved steam-only injection or co-injectionof C6H14 with steam. The maximum allowed injection pressureof 10 MPa restricted the amount of steam injected. Theminimum BHP was 150 kPa. In these simulations, each cyclehad an injection period of 10 days, a soak period of 10 days,and a production period of 325 days.

Two different grid systems were used. The first represented asingle 500 m long horizontal well and a 49 x 20 x 28 grid wasused. The second represented two 500 m long horizontal wells.It had 98 x 20 x 28 grid blocks and represented a reservoirregion of 582 m wide, 1,000 m long, and either 11.6, 14, 26 m,or 38 high. The 500 m long cyclic wells were spaced 180 mapart.

In Run 3D-MW-6, steam-C6H14 co-injection (5 mole% C6H14)over 24 cycles (5 day soaks and 93 day production periods)resulted in a CDOR/well of 35.8 m3/d, a CSOR of 8.1 m3/m3,and a 0.88 liquid m3/m3 net solvent to oil ratio. The low CDORas compared to the 2-D simulations was due primarily to thethin pay (14 m) used in the 3-D simulations and to the limit of500 m3/d imposed on the liquid production rate. Figures 33 to36 show profiles for Runs 3D-MW-6. At the end of the firstinjection period (30 days) of Run 3D-MW-6, high temperatureswere obtained above the injection wells but the temperaturezone had not moved very far laterally (Figure 33). In contrast,high pressures were experienced at the reservoir boundaries(Figure 34).

After 3,900 days the temperature zones of influence for the twowells in Run 3D-MW-6 had still not overlapped (Figure 35).Figure 36 shows contrasting profiles (temperature pressure,saturations, C6H14 mole fraction in oil) for Runs 3D-MW-6 (noshale layer). They show the high C6H14 mole fraction in the oil,the low oil saturation, and the high water saturation, above bothends of the horizontal well.

Investigation of Reservoir, Injection Fluidand Operation Strategy on HW-CSS-S

Effect of Reservoir Properties

PAY THICKNESS

Both 2-D and 3-D simulations were preformed to evaluate theeffect of pay thickness. In the 2-D single well simulations, athicker pay had a lower net C6H14/oil ratio than a thinner pay.The oil rate for a pair of horizontal wells was three times higherfor a 26 m thick pay than for a 11.6 m thick pay. The CSORand net C6H14/oil ratio were 13% and 77% higher, respectivelyfor the thinner pay. In the simulations each cycle consisted of20 days of C6H14 injection before steam-only injection in eachcycle. The solvent and steam were not co-injected.In the 3D single well simulations, for steam-C6H14 (5 mole%)co-injection, a thicker pay (26 m versus 14 m) had 47% higheroil production and 20% lower CSOR. The net C6H14/oil ratiowas 32% greater for the thicker pay as a result of the very lowpercentage of C6H14 recovered at the higher pay thickness (20%for 26 m of pay versus 51% for 14 m of pay).

ABSOLUTE PERMEABILITY AT MAXIMUM DILATION

Increasing the absolute permeability at maximum dilation of agrid block from 1.5 to 38.0 Darcy allowed more steam to beinjected before the maximum allowed injection pressure (10MPa) was reached. This resulted in a three-fold increase inCDOR, a 26% increase in CSOR, and a 53% decrease in netC6H14/oil ratio. 3-D simulations also showed an increase inCDOR and CSOR and a decrease in net C6H14/oil ratio if theallowed liquid production rate was higher.

Effect of Solvent Type and Solvent Concentration

SOLVENT TYPE

The solvents considered were C6H14, CH4, and condensate. Forthe injection strategy used (20 days of solvent injectionpreceded each steam-only injection period in a cycle),condensate was significantly superior to C6H14 and CH4 as itresulted in a much lower CSOR (0.57 versus 3.86 and 4.15 m3

CWE/m3). However, the net solvent to oil ratio was very highfor both condensate (11.57 liquid m3/m3) and C6H14 (3.37 liquidm3/m3). If this solvent can be recovered with an effectivefollow-up process such as flooding then this process can beviable. CH4 injection resulted in a very low CDOR of 5 m3/dversus 39 and 35 m3/d for condensate and C6H14.

C6H14 CONCENTRATION IN STEAM

In these simulations of CSS with the co-injection of C6H14 andsteam, the CDOR increased significantly with increase in C6H14

concentration in the injected steam (Table 3 and Figure 37) upto a 5 mole% C6H14 concentration in steam. Above 5% C6H14

concentration, there was a marginal increase in oil productionwith increasing C6H14 concentration. However, the CSOR wassignificantly reduced with increasing C6H14 concentration. Thenett C6H14 to oil ratio increased with C6H14 concentration in theinjected steam (Table 3) of up to 10 mole % C6H14, and itappears that the limiting value for the nett C6H14 to oil ratiowould reach about 1 (m3 of liquid solvent per m3 of oil) at aconcentration of about 20 mole % C6H14 in injected steam.

Table 3. Effect of C6H14 concentration on steam-C6H14 co-injection process

C6H14

ConcentrationCDOR(m3/d)

CSOR(m3/m3)

Nett C6H14 to oil ratio(liquid m3/m3)

0 36.3 3.40 0

1 37.9 3.23 0.05

2 42.0 2.89 0.03

3 44.9 2.67 0.21

5 53.2 2.22 0.45

10 57.2 2.00 0.84

Effect of Operating Strategies

IMPACT OF MAXIMUM BOTTOMHOLE LIQUIDPRODUCTION RATE

For steam-C6H14 co-injection, an increase in the maximumallowed bottomhole liquid production rate from 500 m3/d to2,500 m3/d increased the CDOR from 56.8 to 100.0 m3/d but atthe expense of increasing the CSOR from 4.51 to 8.45 m3

8

CWE/m3. The maximum CDOR was at a maximum liquid rateof 2,000 m3/d (Figure 38). The net C6H14 to oil ratio wasdramatically decreased from 0.77 to 0.09 liquid m3/m3 when theliquid production rate was increased to 2,500 m3/d.

EFFECT OF INFILL HORIZONTAL PRODUCER

For steam-C6H14 co-injection, an infill horizontal producermidway between two horizontal wells, which were 0.75 mabove the bottom of the pay (Figure 4), was beneficial andincreased the CDOR by 31%, reduced the CSOR by 9% and thenet C6H14 to oil ratio by a factor of 3 during a cyclic steam-solvent process. The closer the infill producer was to thebottom of the pay, the better was its performance. When theinfill well was 0.75 m above the bottom of the 14 m pay, theCDOR, CSOR, and net C6H14/oil ratio were 20% greater, 63%lower, and 21% lower, respectively, than when the infill wellwas 11.75 m above the pay bottom.

EFFECT OF INFILL WATER INJECTOR

In steam-C6H14 co-injection simulations, continuous hot water(100 C) injection in an infill well (Figure 4) reduced steaminjection in the cyclic wells by a factor of 48 as compared towhen the infill producer well was used. This was a result of itsimpact on reservoir pressure and caused a five-fold reduction inCDOR and an order of magnitude decrease in CSOR. As aresult of the BHP being limited to 10 MPa, the average waterinjection rate was 1,282 m3/d.

Horizontal versus Slant Wells

For a 3D homogeneous reservoir (Figure 31), a pair ofhorizontal wells recovered only 51% of the injected C6H14 ascompared to 60% for a pair of slant wells. However, use ofhorizontal wells resulted in a significantly higher CDOR (71.6versus 54.0 m3/d) and lower CSOR 8.16 versus 11.28 m3

CWE/m3) and net C6H14/oil ratio (0.88 versus 0.98 liquidm3/m3) than did the slant wells.

Conclusions

1. The best injection strategy for CSS-S with horizontal wellsinvolves solvent injection either co-injection with thesteam or alternate solvent (CSI) and steam (CSS) cycles.

2. Increasing the soak period from 5 to 15 days had minimalimpact on CSS performance.

3. Increasing the maximum allowed liquid production ratefrom 1 to 5 m3/d/m of well length had a major impact onCSS behaviour.

4. If steam and solvent are to be injected separately in acycle, it is best to inject the solvent before the steam ratherthan after it. Steam injection before the solvent increasesthe reservoir temperature and reduces solvent solubility.

5. Solvent injection before steam in the same cycle results insignificant solvent losses in the reservoir. This solventmay be recovered by a follow-up process such as a steamor non-condensible gas flood.

6. Water injection at an infill horizontal well had a negativeimpact by reducing pressure cycling (i.e. reduceddrawdown) in the reservoir thereby reducing steaminjection.

7. An infill horizontal producer significantly improved oilproduction.

8 For a uniform formation, horizontal wells produced moreoil than slant wells but had greater solvent retention in thereservoir.

9. Use of the Beattie Boberg model as a predictive toolrequires knowledge of formation characteristics such asthe pressure at which dilation starts to occur and howmuch re-compaction occurs during production. Its use isalso hindered by the fact that it does not considergeotechnical behaviour of the formation and the impact ofCSS on formation stress states. In the absence of afunctioning geomechanics model, the Beattie-Bobergmodel is of use in elucidating mechanisms and the effectof different parameters on CSS. An alternative approach isto use the Ito Sand Deformation model.

Acknowledgements

Authors would like to thank the AERI/ARC/Core/IndustryResearch program for their financial and technical support. Thecontribution of Valerie Pinkoski in editing this paper is verymuch appreciated.

NOMENCLATURE

CH4 methaneC6H14 n-hexaneCDOR : calendar day oil rate = total oil production/total

number of days in steam cycles (m3/d)CRD : formation compressibility for dilated blocks in

Beattie-Boberg model (kPa-1)CSI: cyclic solvent injection.CSS : cyclic steam stimulationCWE: cold water equivalent = volume of water used to

generate the steamFR : Fraction of total dilation not recovered on re-

compaction in Beattie-Boberg modelGOR : volume of dissolved gas per unit volume of oil

(std m3/m3)HW-CSS: cyclic steam stimulation using horizontal wellsHW-CSS-S: cyclic steam stimulation with solvent using

horizontal wellskh: absolute permeability in horizontal direction

(Darcy)k

rgro:gas phase relative permeability at Swc + Sorg

krocw

: oil phase relative permeability at irreducible water

saturationkrow : oil phase relative permeability in the presence of

waterkrw: water phase relative permeabilityk

rwc:water phase relative permeability at residual oil

saturationkv : absolute permeability in vertical direction (Darcy)Ki : yi/xi. K

iis calculated from KV values as follows:

Ki= (KV1i/P + KV2i *P +KV3i)*eKV4i/(T-KV5i)

P : pressure (kPa)PBASE : reference pressure in Beattie-Boberg model (kPa)Pcgend: maximum value of gas-oil capillary pressure

(kPa)Pcwend : maximum value of water-oil capillary pressure

(kPa)PDILA : pressure in Beattie-Boberg model at which

dilation starts to occur as the pressure is increasedduring steam injection (kPa)

9

PERMI: current absolute permeability in I direction of agrid block in Beattie-Boberg model (Darcy)

PERMIinitial : initial absolute permeability in I direction inBeattie-Boberg model

PERMJinitial : initial absolute permeability in J direction inBeattie-Boberg model

PERMKinitial = initial absolute permeability in K directionin Beattie-Boberg model

PERMUL : represents PERMULI, PERMULJ, or PERMULKPERMULI: multiplier in Beattie-Boberg model used in

equation to determine the current absolutepermeability in I direction of a grid block(PERMI) from its initial absolute permeability(PERMIinitial)

PERMULJ : multiplier in Beattie-Boberg model used inequation to determine the current absolutepermeability in I direction of a grid block(PERMI) from its initial absolute permeability(PERMJinitial)

PERMULI: multiplier in Beattie-Boberg model used inequation to determine the current absolutepermeability in I direction of a grid block(PERMI) from its initial absolute permeability(PERMKinitial)

PORRATMAX: Maximum allowed proportional increase inporosity in a block in Beattie-Boberg model

PPACT: Pressure at which re-compaction begins duringproduction in Beattie-Boberg model (kPa)

SOR : steam-oil ratio = volume of injected steamCWE/volume of produced oil

Sgr:

critical gas saturation

Sorw:

residual oil saturation for oil-water system

Sorg

: residual oil saturation for oil-gas system

SW : water saturationS

wr : irreducible water saturation

visi : viscosity of component I in oil phase (mPa.s)visoil : oil phase viscosity (mPa.s)xi : mole fraction of component i in oil phaseyi : mole fraction of component i in gas phaseP : Porosity at pressure P in Beattie-Boberg modelPBASE : Porosity at base pressure (PBASE) in Beattie-

Boberg model : porosityPV: Pore volume [cm3]

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BEATTIE, C.I., BOBERG, T.C., and McNAB, G.S.,"Reservoir Simulation of Cyclic Steam Stimulation in theCold Lake Oil Sands", SPERE, pp. 200-206, May 1991.

COSENTINO, L., SPOTTI, G., GONZALEZ, J.E., ARAUJO,Y., and HERRERA, J., "Cyclic Steam Injection on ParallelHorizontal Wells: Geostatistical Description, ThermalSimulation and Field Experience", SPE 49017, pp293-303,1998 Annual Technical Conference and Exhibition, NewOrleans, Louisiana, 27 - 30 September, 1998.

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DENBINA, E.S., BOBERG, T.C., and ROTTER, M.B.,Evaluation of Key Reservoir Mechanisms in the EarlyStages of Steam Stimulation at Cold Lake, SPERE, pp.207-211, May 1991.

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ESCOBAR, M.A., VALERA, C.A., and PEREZ, R.E., "ALarge Heavy Oil Experience in Lake Maracaibo Basin:Cyclic Steam Injection Experiences", SPE 37551, pp337-347, 1997 SPE International Thermal Operations & HeavyOil Symposium, Bakersfield, California, 10 - 12 Feb., 1997

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10

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11

.

ProductionRecompaction

PDILAPo

Po

= initial reservoir pressure = 3,000 kPaa

PDILA = dilation pressure = 7,515 kPaa

-PPACT = recompaction pressure = 4,137 kPaa

Production

Dilation

Po

rosi

ty

Pore PressurePPACT Po

o

Injection

Start of Injection

Max

Figure 2: Dilation and re-compaction

(Beattie, Boberg, and McNab Model)

Figure 1: Saturation pressure and temperaturefor different fluids

-250

-200

-150

-100

-50

0

50

100

150

200

250

0 250 500 750 1000 1250 1500 1750 2000

Saturation Pressure (kPaa)

Satu

rati

on

Tem

pera

ture

(C)

Methane Ethane Propane

Butane Isobutane Pentane

Hexane CO2 Water

Figure 4: Grid for multiple well 2-D simulations withhorizontal infill injector or producer

Reservoir: 804 m x 1 m x 11.6 m/14 m/26 mhigh Blocks: 98 x 1 x 28

Infillinjector

Infill producer

Wells

Figure 6: C6H14 in reservoir for 2D-SWStrategies 1, 10, and 14

0

50000

100000

150000

200000

250000

300000

0 500 1000 1500 2000 2500 3000 3500 4000

Time (days)

Nett

Hexan

e(s

tdm

3)

Run 14

Run 10

Run 1

0

50000

100000

150000

200000

250000

300000

0 500 1000 1500 2000 2500 3000 3500 4000

Time (days)

Nett

Hexan

e(s

tdm

3)

Run 14

Run 10

Run 1

C6H14-only cycles

Steam-only

Figure 5: Cumulative SOR for 2D-SWStrategies 1, 2, 10, and 14

0

1

2

3

4

5

6

7

8

9

10

0 500 1000 1500 2000 2500 3000 3500 4000 4500

Time (days)

Cu

mu

lati

ve

Ste

am

-Oil

Ra

tio

Run 14

Run 10

Run 1

Run 2

0

1

2

3

4

5

6

7

8

9

10

0 500 1000 1500 2000 2500 3000 3500 4000 4500

Time (days)

Cu

mu

lati

ve

Ste

am

-Oil

Ra

tio

Run 14

Run 10

Run 1

Run 2

C6H14-only cycles

Steam only cycles

Figure 3: Grid for single well 2-D simulations

Reservoir: 402 m x 1 m x 26m high Blocks: 49 x 1 x 28

x x x

A:10,1,18 B:15,1,18 C:20,1,18

x x

D:15,1,26 F:20,1,26

x

E:20,1,26

12

Note: SH = steam-C6H14; HO = C6H14-only, and SO = steam-only

Figure 11: Water saturation versus time at locationsA, B, and C in Figure 3 for 2D-SW Strategy 14

A = 10 1 18

C = 20 1 18

B = 15 1 18A = 10 1 18

C = 20 1 18

B = 15 1 18

SH HO SH HO SH HO SO

A = 10 1 18

C = 20 1 18

B = 15 1 18

A = 10 1 18

C = 20 1 18

B = 15 1 18

Figure 8: Pressure versus time at locations A,B, and C in Figure 3 for 2D-SW Strategy 14


Figure 12: Gas saturation versus time at locationsA, B, and C in Figure 3 for 2D-SW Strategy 14

A = 10 1 18

C = 20 1 18

B = 15 1 18

A = 10 1 18

C = 20 1 18

B = 15 1 18

A = 10 1 18

C = 20 1 18

B = 15 1 18

A = 10 1 18

C = 20 1 18

B = 15 1 18

Figure 10: Live oil saturation versus time atlocations A, B, and C for 2D-SW Strategy 14

Figure 9: Temperature versus time at locations A,B, and C in Figure C for 2D-SW Strategy 14

A = 10 1 18

C = 20 1 18

B = 15 1 18

A = 10 1 18

C = 20 1 18

B = 15 1 18


Figure 7: C6H14 injected and produced for 2D-SWStrategies 1, 10, and 14

0.0E+00

2.0E+05

4.0E+05

6.0E+05

8.0E+05

1.0E+06

1.2E+06

1.4E+06

0 500 1000 1500 2000 2500 3000 3500 4000

Time (days)

Cum

ula

tive

Hexane

(std

m3) Run 14

Run 10

Run 1

Inj

Prod

Inj

Prod

Inj

Prod0.0E+00

2.0E+05

4.0E+05

6.0E+05

8.0E+05

1.0E+06

1.2E+06

1.4E+06

0 500 1000 1500 2000 2500 3000 3500 4000

Time (days)

Cum

ula

tive

Hexane

(std

m3) Run 14

Run 10

Run 1

Inj

Prod

Inj

Prod

Inj

Prod

End Injection 6: Hexane-only (715 days) End Production 6 (813 days)

End Injection 22: Hexane-only (3,411 days) End Production 22 (3,509 days)

End Production 24 (3,900 days)

End Injection 3: Steam-hexane (295 days) End Production 3 (393 days)

End Injection 23: Steam-only (3,605 days) End Production 23 (3,703 days)

End Injection 24: Steam-only (3,802 days)












A = 10 1 18

C = 20 1 18 B = 15 1 18

A = 10 1 18

C = 20 1 18 B = 15 1 18

Figure 14: CH4 mole fraction in oil versus time atlocations A, B, and C for 2D-SW Strategy 14

A = 10 1 18

C = 20 1 18

B = 15 1 18

A = 10 1 18

C = 20 1 18

B = 15 1 18

Figure 13: C6H14 mole fraction in oil versus timeat locations A, B, and C for 2D-SW Strategy 14

13

Figure 15: C6H14 mole fraction in oil during Strategy 14

14

kPa

C

Pressure

Gas Saturation

Oil Saturation

Temperature

Water Saturation

Strategy 14

XC6H14

Figure 20: Profiles at end (3,900 days) of Strategy 14

Figure 19: Gas phase mole fractions and gasvelocity vectors at 3,900 days of Strategy 14

watery

hexaney

A = 10 1 18

C = 20 1 18

B = 15 1 18

A = 10 1 18

C = 20 1 18

B = 15 1 18

Figure 17: C6H14 mole fraction in gas versus time atlocations A, B, and C for 2D-SW Strategy 14

Figure 16: CH4 mole fraction in gas versus time atlocations A, B, and C for 2D-SW Strategy 14

A = 10 1 18

C = 20 1 18

B = 15 1 18

Strategy 14

Strategy 10

Strategy 1

Strategy 2

Figure 18: Cumulative CH4 production duringStrategies 1, 2, 10, and 14

15

Figure 22: Oil phase viscosity profiles during Strategies 2 and 14

End Injection 6: Steam -only (740 days) End Injection 6: Hexane -only (715 days)

Strategy 2 Strategy 14

End Injection 21: Steam -only (3,320 days) End Injection 22: Hexane -only (3,411 days)

End Injection 22: Steam -only (3,802 days)

End Injection 3: Steam -hexane (295 days)


End Injection 3: Steam -only (305 days)

mPa.s

End Injection 6: Steam -only (740 days) End Injection 6: -only (715 days)












mPa.smPa.s

End Injection 6: Steam-only (740 days) End Injection 6: Hexane-only (715 days)


End Injection 21: Steam-only (3,320 days) End Injection 22: Hexane-only (3,411 days)


End Injection 3: Steam-hexane (295 days)


End Injection 3: Steam-only (305 days)

C

End Injection 6: Steam-only (740 days) End Injection 6: Hexane-only (715 days)


End Injection 21: Steam-only (3,320 days) End Injection 22: Hexane-only (3,411 days)


End Injection 3: Steam-hexane (295 days)


End Injection 3: Steam-only (305 days)

CC

Figure 21: Temperature profiles during Strategies 2 and 14

16

A = 10 1 18

C = 20 1 18

B = 15 1 18

A = 10 1 18

C = 20 1 18

B = 15 1 18

Figure 27: Oil viscosity versus time at locationsA, B, and C (Figure 3) for 2D-SW Strategy 14

Strategy 14: 20-1-26

Saturation T ( C̊) of water based on Ptotal

Block T ( C̊)Saturation T ( C̊) of water based on PPwater

Figure 25: Temperature and saturationtemperature at Block 20-1-26 during Strategy 14

End Soak 14 End Prod 14

End Soak 17

End Soak 22

End Soak 24

End Prod 17

End Prod 22

End Prod 24


End Soak 17

End Soak 22

End Soak 24

End Prod 17

End Prod 22

End Prod 24


End Soak 17

End Soak 22

End Soak 24

End Prod 17

End Prod 22

End Prod 24

Figure 23: Gas saturation during Strategy 14

Figure 24: Temperature and saturation temperatureat Block 15-1-26 (D in Figure 3) during Strategy 14







Figure 26: Temperature and saturation temperatureat Block 25-1-26 (E in Figure 3) during Strategy 14

17

m C̊

End 3rd

soakEnd 9

thsoak End 14

thsoak End 17

thsoak End 22

ndsoak End 24

thsoakEnd 6

th

Soak

Strategy 14: alternating groups of steam-C6H14 and C6H14-only cycles

Strategy 2: steam-only injection

Figure 28: Temperature profiles at end of some soak periods in Strategies 2, 1, and 14

Strategy 1: steam-C6H14 co-injection

Strategy 2: steam-only injection

18

Strategy 2: steam-only cycles

Strategy 1: steam-C6H14 co-injection

Strategy 14: alternating groups of steam-C6H14 and C6H14-only cycles

mPa.sm

Figure 29: Oil phase viscosity profiles at end of some soak periods in Strategies 2, 1, and 14

End 3rd

soakEnd 9

thsoak End 14

thsoak End 17

thsoak End 22

ndsoakEnd 6

th

soak

End 24th

soak

19

Figure 31: Hexane mole fraction in oil profiles at end of some soak periods in Strategies 2, 1, and 14

Strategy14:alternating groups ofsteam-hexaneand hexane-onlycycles

m

Strategy1 (steam-hexane co-injection)

End3rd

soakEnd9

th

soakEnd14th soak End17th soak End22ndsoakEnd 6th

soakEnd24

thsoak

Strategy 1: steam-C6H14 co-injection cycles

Strategy 14: alternating groups of steam-C6H14 co-injection and C6H14-only cycles

Figure 30: Dead oil saturation profiles for Strategies 1, 2, 10 and 14

End Strategy 1 - 3,818 days End Strategy 2 - 3,818 days




20

I = 25

J = 10

k = 5

°C

k = 5 J=

10

1,000 m

40

2m

14

m1

4m

X-section along wells

X-section perpendicular to wells

Plan view

k = 2

Run 3D-MW-6 Cycles:Steam-C6H14 co-injection14 m pay,180 m spacing

Figure 33: Temperature profiles at end of first injection period (30 days) of Run 3D-MW-6

So & Sg

End of Production of Strategy 14: (3,900 days)

Sg & GasVelocity Vectors

So & OilVelocity Vectors

End Injection 6 of Strategy 14: C6H14-only (715 days)



End of Production 6 of Strategy 14: (813 days)



End of Injection 24 of Strategy 14: Steam-only (3,808 days)


So & Oil

Velocity Vectors

Figure 32: So, Sg and velocity vectors for Strategies 14

21

I = 25

J = 10

k = 5

k = 5 J=

10

1,000 m

40

2m

14

m1

4m


X-section perpendicular towells

Plan view

kPaa

k = 2

Run 3D-MW-6Cycles:

Steam-C6H14 co-injection

Figure 34: Pressure profiles at end of first injection period (30 days) of Run 3D-MW-6

I = 25

J = 10

k = 5

k = 5J=10

1,000 m

402

m14

m14

m


X-section perpendicularto wells

Plan view

k = 2

°C

Run 3D-MW-6 Cycles:Steam-hexane co-injection

14 m pa,180 m spacing

No shale

Figure 35: Temperature profiles at the end (3,900 days) of Run 3D-MW-6

22

0.00E+00

1.00E+05

2.00E+05

3.00E+05

4.00E+05

5.00E+05

6.00E+05

0.0 2.0 4.0 6.0 8.0 10.0 12.0

Hexane in Injected Steam (mole %)

Cu

mu

lati

ve

Pro

du

cti

on

(m3)

0.00E+00

5.00E+04

1.00E+05

1.50E+05

2.00E+05

2.50E+05

Max.In

jecti

on

Rate

(m3/d

)

Oil Produced

Water Produced

Solvent Injected

Figure 37: Effect of C6H14 concentration in steam onproduction with CWE = 1500 m

3/d (Quality = 0.8)

Figure 40: Effect of pressure on permeability

0

20

40

60

80

100

120

0 500 1000 1500 2000 2500 3000

Max Liquid Rate (Bottomhole Conditions) at 500 m Long Producer (m3/d)

Oil

Rate

(m3/d

)

0

1

2

3

4

5

6

7

8

9

Cum

ula

tive

SO

Ror

Cum

ula

tive

Nett

C6/O

ilR

atio

Average Oil Rate

Cumulative SOR

Cumulative Nett C6/Oil Ratio

Oil Rate

C6/Oil

SOR

Figure 38: Effect of downhole liquid rate in 2-Dsingle well simulations

C

Pressure

Gas Saturation

Oil Saturation

Temperature

kPa

xhexane W ater Saturation

Figure 36: Profiles at I = 25 at end (3,900 days) of Run 3D-MW-6

0

10

20

30

40

50

60

70

80

3000 4000 5000 6000 7000 8000 9000 10000

Pressure (kPaa)

Po

rosit

y(%

)

= initial * eCRD * (P –Pbase)

CRD = formation compressibility for dilated blocks =0.0001 kPa -1

Pbase = 3,000 kPaainitial = 0.35PORRATMAX = 1.3Max allowed = initial * PORRATMAX = 1.3 * 35 = 45.5%

Limit = 45.5%

0

10

20

30

40

50

60

70

80

3000 4000 5000 6000 7000 8000 9000 10000

Pressure (kPaa)

Po

rosit

y(%

)

= initial * eCRD * (P –Pbase)

CRD = formation compressibility for dilated blocks =0.0001 kPa -1

Pbase = 3,000 kPaainitial = 0.35PORRATMAX = 1.3Max allowed = initial * PORRATMAX = 1.3 * 35 = 45.5%

Limit = 45.5%

Figure 39: Effect of pressure on porosity

23

Appendix A - Beattie-Boberg Model

In the Beattie Boberg model (1991), it is assumed that elastic conditions apply (pore pressure increases quickly with steam injection) untila specified pressure (PDILA) is reached at which point the pores expand (dilation) with continued steam injection. During production, thepores stay dilated until the pressure falls below another specified pressure (PPACT). At this time, the pores start to shrink (re-compact) asthe pressure decreases further due to continued fluid production.

Relevant terms are defined below.

PBASE = Reference pressure

P = Porosity at pressure P= PBASE * eCRD * (P - PBASE)

PBASE = porosity at PBASE

CRD = Dilated rock compressibility and is about 100 times greater than the un-dilated compressibility.

PDILA = Pressure at which dilation begins

PPACT =Pressure at which re-compaction begins. PPACT can be obtained by matching the pressure response duringproduction. If inter-well communication exists, it is crucial to match the pressure response as the amount ofcommunication depends on the pressures of the communicating wells. Pressure changes also affect steam flashingand solution-gas drive.

FR = Fraction of total dilation not recovered on re-compaction. FR can be used to match fluid production.

PORRATMAX = Maximum relative porosity increase in a block = maximum permitted porosity/initial porosity. It can beobtained by matching cumulative steam injection.

PERMI = PERM initial * ePERMULI * ( - initial)/(1 - initial)

PERMI = absolute permeability in the I direction after allowance for dilation.

In most of the simulations discussed in this report, Denbina's values (1991) (Table A-1) for the Beattie-Boberg properties were used. Thedependency of porosity and absolute permeability in the I direction (horizontal and perpendicular to the well) or J direction on porepressure are shown in Figures 39 and 40 respectively for a PERMULI value of 4.5 and a PORRATMAX value of 1.3.

Beattie et al.,1991, allowed for relative permeability hysteresis using scanning curves and fracture formation in specified blocks byimposing an increased transmissibility during injection for specified blocks in the fracture plane and using the original transmissibilitiesfor production periods. Fracture permeabilities at the injection pressure were typically 100 to 500 times those at the reservoir pressure.

Table A-1. Beattie-Boberg Properties for Cold Lake (Denbina, 1991)

Permeability (Darcy)

CRD 1 x 10-4

FR 0.35

PBASE (kPa) 3,000

PDILA (kPa) 7,515

PERMULI 4.5

PERMULJ 4.5

PERMULK 4.5

PORRATMAX 1.3

PPACT (kPa) 4,137

24

Appendix B

Table B-1. Properties used in the simulations

HVR = first coefficient in heat of vaporization correlation (J/(mol . C0.38)

Table B-2. Oil and C6H14 properties used in Athabasca 2-D simulations

The oil and dissolved C6H14 viscosities are provided at different temperatures in Table B-3.The linear logarithmic mixing rule was used to determine the oil phase viscosity i.e. ln (visoil) = xi ln (visi).

Parameter Value

Porosity (%) 35.0

Absolute permeability in I and J directions (Darcy) 1.5

Absolute permeability in K direction (Darcy) 0.45

Initial oil saturation (So) 0.7

Initial water saturation (Sw) 0.3

Initial pressure (kPa) 3,100

Initial temperature (C) 13

Initial oil mole fraction in oil phase 0.8189

Initial CH4 mole fraction in oil phase 0.1811

Oil compressibility (kPa-1) 2.265 x 10-7

Rock compressibility (kPa-1) 1.0 x 10-6

Rock specific heat (J/m3 C) 2.04 x 106

Rock thermal conductivity (J/m . day. C) 6.60 x 106

Water thermal conductivity (J/cm . min. C) 5.35 x 104

Oil thermal conductivity (J/cm . min. C) 1.15 x 104

Gas thermal conductivity (J/cm . min. C) 2,880

Steam quality 0.8

Oil specific heat (J/mol.C) 1,092

C6H14 specific heat (J/mol.C) 192.2

CH4 specific heat (J/mol.C) 121.1

C6H14 HVR (J/(mol . C0.38)) 4,143

CH4 HVR (J/(mol . C0.38)) 1,556

Surface pressure (kPa) 101.

Surface temperature (C) 15

Oil Dissolved C6H14

Molecular weight 533 86.178

Specific gravity 0.999 0.664

Liquid Compressibility (kPa-1) 2.2656 x 10-7 7.5 x 10-6

Pc (kPa) 821.746 2,969.0

Tc (C) 639.15 234.25

Liquid molar density (mole/m3) 1,874 12,330

25

Table B-3. Viscosities in oil phase at different temperatures

Temperature(C)

Dead Oil Viscosity(mPa.s)

C6H14 Viscosity(mPa.s)

CH4 Viscosity(mPa.s)

0 784887.7 125.494 9.09

20 38925.73 31.891 2.31

40 4319.322 13.801 1

60 836.4406 8.305 0.602

80 240.2033 6.134 0.444

100 91.68443 5.144 0.373

120 43.1393 4.664 0.338

140 23.73272 4.434 0.321

160 14.69947 4.333 0.314

180 9.972517 4.3 0.311

200 7.262009 4.245 0.307

220 5.590853 4.19 0.303

240 4.49871 4.134 0.299

260 3.750363 4.079 0.295

280 3.217241 4.024 0.291

300 2.824972 3.969 0.287

320 2.528413 3.913 0.283

340 2.299011 3.858 0.279

360 2.118051 3.803 0.275

374 2.013256 3.748 0.271

Relative Permeability End-points:

Swr

= irreducible water saturation = 0.29

Sorw

= residual oil saturation for oil-water system = 0.25

Sorg

= residual oil saturation for oil-gas system = 0.2

Sgr

= critical gas saturation = 0.05

krocw

= oil relative permeability at irreducible water saturation = 0.8

krwc

= water relative permeability at residual oil saturation = 0.15

krgro

= gas relative permeability at Swc + Sorg = 0.408

Capillary Pressure End-points:

Pcwend = maximum value of water-oil capillary pressure (kPa) = 0.6Pcgend = maximum value of gas-oil capillary pressure (kPa) = 2.0

26

Table B-4. C6H14 K values used in the simulations

Pressure\Temperature 10 C 100 C 200 C 300 C 370 C

200 kPa 0.05047 1.23010 8.73008 29.34172 53.77836

1,000 kPa 0.01009 0.24602 1.74602 5.86834 10.75567

2,000 kPa 0.00505 0.12301 0.87301 2.93417 5.37784

3,000 kPa 0.00336 0.08201 0.58201 1.95611 3.58522

5,000 kPa 0.00202 0.04920 0.34920 1.17367 2.15113

7,000 kPa 0.00144 0.03515 0.24943 0.83833 1.53652

10,000 kPa 0.00101 0.02460 0.17460 0.58683 1.07557

Table B-5. Diluent K values at 1,500 kPa

K at 10C K at 100C K at 200C

COMP1 0.1139 0.6583 2.0228

COMP2 0.0008 0.0043 0.0471

COMP3 0.0000 0.0013 0.0451

COMP4 0.0000 0.0013 0.0451

27

Appendix C - Injection Strategies Considered in 2-D Single Well Simulations

Table C-1. Results for Different Solvent Injection Strategies in 2-D Single Well Simulations

Run StrategyAverage

CDOR for500 m Well

CSORNet

C6H14/OilRatio

C6H14

Produced/C6H14

Injected(%)

OilRecovery

(%)

2D-SW-1CSS with 5% C6 co-injection, 10 day soak

(Strategy 1, Table B-1)63.5 4.41 0.78 18.1 18.9

2D-SW-2CSS (steam-only)

(Strategy 2, Table B-2)47.3 7.50 - - 14.1

2D-SW-3Cycles: 3 CSS steam-only, 10 x (CSI, CSS)

(Strategy 3, Table B-3)47.7 6.28 0.55 90.4 14.2

2D-SW-4Cycles: 3 CSS cycles, 20 CSI cycles

(Strategy 4, Table B-4)50.6 0.77 1.20 93.1 15.1

2D-SW-5Cyclic solvent injection (CSI)

(Strategy 5, Table B-5)54.8 0.00 1.37 90.8 16.3

2D-SW-620 days of C6H14-only injection before steam-

only in each cycle(Strategy 6, Table B-6)

54.5 3.62 1.40 81.2 16.2

2D-SW-720 days of steam-only before C6H14-only in

each cycle(Strategy 7, Table B-7)

38.5 6.03 0.56 96.8 11.5

2D-SW-8CSS with 5% C6 co-injection, 5 day soak,

(Strategy 8, Table B-8)64.2 4.41 0.79 18.3 19.6

2D-SW-9CSS with 5% C6 co-injection, 15 day soak

(Strategy 9, Table B-9)62.3 4.32 0.77 18.4 19.1

2D-SW-10

Cycles: 3 CSS steam-only, 3 CSI (C6H14), 3CSS steam-only, 3 CSI (C6H14), 3 CSS steam-

only, 5 CSI (C6H14), 4 CSS steam-only(Strategy 10, Table B-10)

56.7 5.25 0.30 95.7 17.3

2D-SW-11

15 days of C6H14-only before steam-only ineach cycle

(Strategy 11, Table B-11)56.5 3.94 1.38 76.7 17.2

2D-SW-12

Cycles: 4 x (3 CSI, 3 CSS steam-only)(Strategy 12, Table B-12)

51.8 5.36 0.51 91.6 15.8

2D-SW-13

3 CSI cycle and then alternate CSS co-injectionwith C6H14 and CSI

(Strategy 13, Table B-13)55.7 4.53 0.62 89.7 17.0

2D-SW-14

Cycles: 3 CSS steam-C6H14 co-injection (5mole% C6H14), 3 C6H14-only injection (CSI), 3CSS steam-C6H14, 5 CSI, 3 CSS steam-C6H14, 5CSI, 2 CSS steam-only to recover C6H14 from

the reservoir(Strategy 14, , Table B-14)

59.0 3.77 0.64 93.5 18.0

2D-SW-15

5 days of C6H14 before steam-C6H14 co-injection in each cycle and soak in 5 days

(Strategy 15, Table B-15)19.4 0.59 0.54 91.0 5.9

28

2D-SW-16

Steam-C6H14 co-injection followed by injecting10 days solvent only and 5 days of soak

(Strategy 16, Table B-16)51.7 4.98 1.26 30.7 15.7

2D-SW-17

Steam- C6H14 co-injection followed by 10 dayssolvent only for first 6 cycles. Mole% C6H14

increased to 10% after Cycle 6. After cycle 16,C6H14 injection for 5 days followed by steam-

C6H14 co-injection.(Strategy 17, Table B-17)

54.0 3.82 1.48 86.4 16.4

In the 2D-SW series, CSI represents cyclic injection of pure C6H14.

In each of these simulations, the maximum allowed liquid production rate for a 500 m long well was 500 m3/d (measured at surfaceconditions).

Table C-2. Injection Strategies 10 and 14 used in Cold Lake Simulations

Strategies 1 & 2 Strategies 10 & 14 Strategy 10 Strategy 14

Cycle

InjectionPeriod for

allStrategies

(days)

Total(inj+soak+prod)

(days)

Cum.Total(days)

Total forStrats. 10 &

14(days)

Cum.Total forStrats. 10

& 14(days)

SteamInj Rate(m3/d)

SolventInj Rate(m3/d)

SteamInj Rate(m3/d)

Mole%

C6H14

SolventInj Rate(m3/d)

1 30 133 133 128 128 3 0 3 5

2 33 136 269 131 259 3.1 0 3.1 5

3 36 139 408 134 393 3.2 0 3.2 5

4 39 142 550 137 530 0 1300 1300

5 42 145 695 140 670 0 1400 1400

6 45 148 843 143 813 0 1500 1500

7 48 151 994 146 959 3.6 0 3.6 5

8 51 154 1148 149 1108 3.7 0 3.7 5

9 54 157 1305 152 1260 3.8 0 3.8 5

10 57 160 1465 155 1415 0 1900 1900

11 60 163 1628 158 1573 0 2000 2000

12 63 166 1794 161 1734 0 2100 2100

13 66 169 1963 164 1898 4.2 0 2200

14 69 172 2135 167 2065 4.3 0 2300

15 72 175 2310 170 2235 4.4 0 4.4 5

16 75 178 2488 173 2408 0 2500 4.5 5

17 78 181 2669 176 2584 0 2600 4.6 5

18 81 184 2853 179 2763 0 2700 2700

19 84 187 3040 182 2945 0 2800 2800

20 87 190 3230 185 3130 0 2900 2900

21 90 193 3423 188 3318 5 0 3000

22 93 196 3619 191 3509 5.1 0 3100

23 96 199 3818 194 3703 5.2 0 5.2

24 - - - 197 3900 5.3 0 5.3

29

Total days in Strategies 1 and 2 includes a 10 day soak and a 93 day production period in every cycle. In Strategy 1, 5 mole% C6H14 wasinjected with the steam. In Strategy 2, no C6H14 was injected i.e. it was steam-only injection.

Total days in Strategies 10 and 14 includes a 5 day soak and a 93 day production period in every cycle

Strategy 10: no C6H14 injected with steam during steam cyclesStrategy 14: C6H14 co-injected with steam during steam cycles

PETSOC-2009-175

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