CA1228020A - Solvent assisted steam injection process for recovery of viscous oil - Google Patents
Solvent assisted steam injection process for recovery of viscous oilInfo
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Abstract
SOLVENT ASSISTED STEAM INJECTION PROCESS
FOR RECOVERY OF VISCOUS OIL
ABSTRACT
A method for recovery of viscous oil from a subterranean, viscous oil-containing formation employing mixture of steam and 2 to 5% of a light solvent having an equilibrium K-value of at least 0.5 at initial formation temperature and pressure that results in maximum solvent efficiency based upon the ratio of cumulative oil recovered to the amount of solvent injected and unrecovered. A predetermined amount of a mixture of steam and 2 to 5% by volume of a light solvent having the desired equilibrium K-value is injected into the lower 50%
or less of the formation via an injection well and fluids including oil and a portion of the light solvent are produced from the upper 50%
or more of the formation via a spaced-apart production well. The amount of steam injected is 0.30 to 0.50 pore volume at a temperature of 500°F to 700°F, a quality of 50 to 90%, and an injection rate of 4 to 7 barrels (CWE) per day per acre-foot of formation. Thereafter, production of fluids including oil and light solvent is continued until steam breakthrough occurs or until the fluid being produced contains a predetermined amount of water, preferably at least 95%.
The method is applied to a viscous oil-containing formation in which either naturally occurring or induced communication exists between the injection well and the production well in the bottom zone of the formation. Suitable light solvents include C1 to C4 hydrocarbons and carbon dioxide. In another embodiment of the invention, injection of the mixture of steam and solvent may be continued and fluids including oil and solvent are produced until steam breakthrough occurs or until the water cut of the produced fluid contains at least 95%
water.
FOR RECOVERY OF VISCOUS OIL
ABSTRACT
A method for recovery of viscous oil from a subterranean, viscous oil-containing formation employing mixture of steam and 2 to 5% of a light solvent having an equilibrium K-value of at least 0.5 at initial formation temperature and pressure that results in maximum solvent efficiency based upon the ratio of cumulative oil recovered to the amount of solvent injected and unrecovered. A predetermined amount of a mixture of steam and 2 to 5% by volume of a light solvent having the desired equilibrium K-value is injected into the lower 50%
or less of the formation via an injection well and fluids including oil and a portion of the light solvent are produced from the upper 50%
or more of the formation via a spaced-apart production well. The amount of steam injected is 0.30 to 0.50 pore volume at a temperature of 500°F to 700°F, a quality of 50 to 90%, and an injection rate of 4 to 7 barrels (CWE) per day per acre-foot of formation. Thereafter, production of fluids including oil and light solvent is continued until steam breakthrough occurs or until the fluid being produced contains a predetermined amount of water, preferably at least 95%.
The method is applied to a viscous oil-containing formation in which either naturally occurring or induced communication exists between the injection well and the production well in the bottom zone of the formation. Suitable light solvents include C1 to C4 hydrocarbons and carbon dioxide. In another embodiment of the invention, injection of the mixture of steam and solvent may be continued and fluids including oil and solvent are produced until steam breakthrough occurs or until the water cut of the produced fluid contains at least 95%
water.
Description
8('~0 SOLVENT ASSISTED STEAM INJECTION PROCESS
_ _ _ . _ FOR RECOVERY OF VISCOUS OIL
This invention pertains to an oil recovery method, and more specifically to a method for recovering viscous oil from subterranean, viscous oil-containing formations employing injection of a predetermined amount of a mixture of steam and 2 to 5~ by volume of a light solvent having an equilibrium K-value of at least 0.5 at initial formation temperature and pressure that results in maximum solvent efficiency.
Many oil reservoirs have been discovered which contain vast quantities of oil, but little or no oil has been recovered from many of them because the oil present in the reservoir is so viscous that it is essentially immobile at reservoir conditions, and little or no petroleum flow will occur into a well drilled into the formation even if a natural or artificially induced pressure differential exists between the formation and the well. Some form of supplemental oil recovery must be applied to these formations which decrease the viscosity of the oil sufficiently that it will flow or can be dispersed through the formation to production well and therethrouyh to the surface of the earth. Tnermal recovery techniques are quite suitable for viscous oil formations, and steam floo~ing is the most successful thermal oil recovery technique yet employed commercially.
Steam may be utilized for thermal stimulation for viscous oil production by means of a steam drive or steam througnput process, in which steam is injected into the formation on a more or less continuous basis oy means of an injection well and oil is recovered from the formation from a spaced-apart production well.
Coinjection of solvents witn steam into a heavy oil reservoir can enhance oil recovery by the solvent mixing with the oil and reducing its viscosity. The use of a solvent comingled with steam ~k ' 1~8( ~20 during a thermal recovery process is described in U.S. Patent N.
4,127,170 to Redford and U.S. Patent No. 4,166,503 to Hall et al.
Applicants' oopending Canadian Patent application filed November 16, 1984, Serial No. 467,975, discloses an oil recovery process employing mixtures of steam and solvent having varying equilibrium K-value and ratio of steam to solvent to maximize solvent efficiency.
The present invention relates to a thermal heavy oil recovery process employing a mixture of steam and 2 to 5~ by volume of a light solvent having an equilibrium K-value of at least û.5 at initial formation temperature and pressure that results in maximum solvent efficiency.
Tne present invention relates to a method for recovering viscous oil from 3 subterranean, viscous oil-containing formation including a tar san~ deposit employing steam ano 2 to 5% by volume of a light solvent having an equilibrium K-value of at least 0.5 at initial formation temperature and pressure that results in maximum solvent efficiency. 9y maximum solvent efficiency is meant the ratio of cumulative oil recovered to the amount of solvent injected and unrecovered at steam breakthrougn. The viscous oil-containing formation contains adequate fluid communication n the oottom zone of the formation between at least one injection well completed in the lower 50% or less of the formation and at least one spaced-apart production well completed in the upper 50~0 or more of tne formation.
A predetermined amount of a mixture of steam anc ~ to 5~ by volume of the light solvent is injected into the lower portion of the formation via the injection well and fluids including oil an5 a portion of tne solvent are recovered from the upper portion 53% or more of the formation via tne production well. Thereafter, production of fluids including oil and solvent is continued from tne upper portion of the formation via tne production well until steam breaktnrough occurs or until a predeter, ned amount of water is contained in the produced fluids, Dreferably at least 95~ wa.er. In a preferre~ emoodiment, tne ('20 F-2~24 ~3-concentration of the lignt solvent in tne steam-nydrocar wn mixture is about 2% by volume and tne equiliorium l~-value is aoout 1.0 at initial formation temperature and pressure. The preferred amount of steam injected is within tne range of .30 to .50 pore volume at a temperature within the range of 500F to 700F and a quality within the range of 50 to 90%. Steam injection rate is preferably 4 to 7 barrels (CWE) of stearn per day per acre-foot of formation. SuitaDle liqht solvents include Cl to C4 nydrocarbons and caroon dioxide.
In another embodiment of the invention, injection of the mixture of steam and solvent may be continued and fluids including oil and solvent are produced until steam obreakthrough occurs or until tne water cut of tne produced fluid contains at least 95% water.
In a preferred embodiment, the invention concerns a metnoc for recovering viscous oil from a suDterranean, viscous oil-containing formation including a tar sand deposit, said formation oeing penetrated by at least one injection well in fluid communication wit~
only tne lower 50% or less of tne oil-containing forrnation and Dy at least one spaced-apart production well in flui~ cornmunication with only the upper 50~0 of tne oil-containing forrnation, comprising:
(a) injecting into tne formation via tne injection well a predetermined amount of a mixture of steam an~ 2 to 5% by volume of a liqnt solvent naving an equiliorium ~-value of at least 0.5 at initial forrnation temperature and pressure to maxlmize solvent efficiency and simultaneously recovering flui~s includinq oil and a portion of the liqnt solvent From the formation via the production well; ando (b) continuinq to recover fluids including oil and liqnt so!vent from the formation via the production ~ell unti1 steam breakthrouqn occurs or until tne flui~
oeinq recovered frorn the production well corrl~rises oredeterminen amount of wat~r.
_ _ _ . _ FOR RECOVERY OF VISCOUS OIL
This invention pertains to an oil recovery method, and more specifically to a method for recovering viscous oil from subterranean, viscous oil-containing formations employing injection of a predetermined amount of a mixture of steam and 2 to 5~ by volume of a light solvent having an equilibrium K-value of at least 0.5 at initial formation temperature and pressure that results in maximum solvent efficiency.
Many oil reservoirs have been discovered which contain vast quantities of oil, but little or no oil has been recovered from many of them because the oil present in the reservoir is so viscous that it is essentially immobile at reservoir conditions, and little or no petroleum flow will occur into a well drilled into the formation even if a natural or artificially induced pressure differential exists between the formation and the well. Some form of supplemental oil recovery must be applied to these formations which decrease the viscosity of the oil sufficiently that it will flow or can be dispersed through the formation to production well and therethrouyh to the surface of the earth. Tnermal recovery techniques are quite suitable for viscous oil formations, and steam floo~ing is the most successful thermal oil recovery technique yet employed commercially.
Steam may be utilized for thermal stimulation for viscous oil production by means of a steam drive or steam througnput process, in which steam is injected into the formation on a more or less continuous basis oy means of an injection well and oil is recovered from the formation from a spaced-apart production well.
Coinjection of solvents witn steam into a heavy oil reservoir can enhance oil recovery by the solvent mixing with the oil and reducing its viscosity. The use of a solvent comingled with steam ~k ' 1~8( ~20 during a thermal recovery process is described in U.S. Patent N.
4,127,170 to Redford and U.S. Patent No. 4,166,503 to Hall et al.
Applicants' oopending Canadian Patent application filed November 16, 1984, Serial No. 467,975, discloses an oil recovery process employing mixtures of steam and solvent having varying equilibrium K-value and ratio of steam to solvent to maximize solvent efficiency.
The present invention relates to a thermal heavy oil recovery process employing a mixture of steam and 2 to 5~ by volume of a light solvent having an equilibrium K-value of at least û.5 at initial formation temperature and pressure that results in maximum solvent efficiency.
Tne present invention relates to a method for recovering viscous oil from 3 subterranean, viscous oil-containing formation including a tar san~ deposit employing steam ano 2 to 5% by volume of a light solvent having an equilibrium K-value of at least 0.5 at initial formation temperature and pressure that results in maximum solvent efficiency. 9y maximum solvent efficiency is meant the ratio of cumulative oil recovered to the amount of solvent injected and unrecovered at steam breakthrougn. The viscous oil-containing formation contains adequate fluid communication n the oottom zone of the formation between at least one injection well completed in the lower 50% or less of the formation and at least one spaced-apart production well completed in the upper 50~0 or more of tne formation.
A predetermined amount of a mixture of steam anc ~ to 5~ by volume of the light solvent is injected into the lower portion of the formation via the injection well and fluids including oil an5 a portion of tne solvent are recovered from the upper portion 53% or more of the formation via tne production well. Thereafter, production of fluids including oil and solvent is continued from tne upper portion of the formation via tne production well until steam breaktnrough occurs or until a predeter, ned amount of water is contained in the produced fluids, Dreferably at least 95~ wa.er. In a preferre~ emoodiment, tne ('20 F-2~24 ~3-concentration of the lignt solvent in tne steam-nydrocar wn mixture is about 2% by volume and tne equiliorium l~-value is aoout 1.0 at initial formation temperature and pressure. The preferred amount of steam injected is within tne range of .30 to .50 pore volume at a temperature within the range of 500F to 700F and a quality within the range of 50 to 90%. Steam injection rate is preferably 4 to 7 barrels (CWE) of stearn per day per acre-foot of formation. SuitaDle liqht solvents include Cl to C4 nydrocarbons and caroon dioxide.
In another embodiment of the invention, injection of the mixture of steam and solvent may be continued and fluids including oil and solvent are produced until steam obreakthrough occurs or until tne water cut of tne produced fluid contains at least 95% water.
In a preferred embodiment, the invention concerns a metnoc for recovering viscous oil from a suDterranean, viscous oil-containing formation including a tar sand deposit, said formation oeing penetrated by at least one injection well in fluid communication wit~
only tne lower 50% or less of tne oil-containing forrnation and Dy at least one spaced-apart production well in flui~ cornmunication with only the upper 50~0 of tne oil-containing forrnation, comprising:
(a) injecting into tne formation via tne injection well a predetermined amount of a mixture of steam an~ 2 to 5% by volume of a liqnt solvent naving an equiliorium ~-value of at least 0.5 at initial forrnation temperature and pressure to maxlmize solvent efficiency and simultaneously recovering flui~s includinq oil and a portion of the liqnt solvent From the formation via the production well; ando (b) continuinq to recover fluids including oil and liqnt so!vent from the formation via the production ~ell unti1 steam breakthrouqn occurs or until tne flui~
oeinq recovered frorn the production well corrl~rises oredeterminen amount of wat~r.
2() The invention will be better understood with reference to the accompanying drawings. In the drawings Figure 1 shows a subterranean, viscous oil-containing formation penetrated by an injection well completed in the lower 50% or less of the formation and a production well completed in the upper 50% or more of the formation witn adequate fluid communication between the wells in the bottom zone of tne formation for carrying out the process of our invention.
Figure 2 illustrates in cross-section the reservoir geometry of the two-dimensional vertical model used in accordance with the invention.
Figure 3 is a graph showing the equili~rium K-v~lues of the solvents tested as a function of temperature and pressure.
Figure 4 is a graph showing the effect of solvent type and volume on incremental cumulative heavy oil recovery as a function of solvent unrecovered.
Referring to Figure 1 of the drawings, there is shown a subterranean, viscous oil-containing fJrmation 10 such as a tar sand deposit penetrated by at least one injection well 12 and at least one spaced-apart production well 14. Injection well 12 is perforated or other fluid flow communication ls estaolisned between the well ~s shown in Figure 1 only with the lower ~6 or less of the vertical thickness of tne formation. ~'roducti~n .ell 14 is compLetea in fluid communication with tne upper 5~3 or inore 3' ~~n~ vertica1 'nicKness of the formation. ~hile recovery of tne type contemplated by the present invention may be carriea out by employing only two wells, it is to oe understood that tne invention is not limited to any particular number of wells. The invention may oe practiced using a variety of well patterns as is ~ell known in tne art of oil recovery, such as an inverted five spot oattern in wnich an injection well is surrounded with four produc~ n wells, or in a line drive arrangement in which a series of aligned njection wells and a series of alignea production wells are utilize~. ~ny number of wells which may be arranged
Figure 2 illustrates in cross-section the reservoir geometry of the two-dimensional vertical model used in accordance with the invention.
Figure 3 is a graph showing the equili~rium K-v~lues of the solvents tested as a function of temperature and pressure.
Figure 4 is a graph showing the effect of solvent type and volume on incremental cumulative heavy oil recovery as a function of solvent unrecovered.
Referring to Figure 1 of the drawings, there is shown a subterranean, viscous oil-containing fJrmation 10 such as a tar sand deposit penetrated by at least one injection well 12 and at least one spaced-apart production well 14. Injection well 12 is perforated or other fluid flow communication ls estaolisned between the well ~s shown in Figure 1 only with the lower ~6 or less of the vertical thickness of tne formation. ~'roducti~n .ell 14 is compLetea in fluid communication with tne upper 5~3 or inore 3' ~~n~ vertica1 'nicKness of the formation. ~hile recovery of tne type contemplated by the present invention may be carriea out by employing only two wells, it is to oe understood that tne invention is not limited to any particular number of wells. The invention may oe practiced using a variety of well patterns as is ~ell known in tne art of oil recovery, such as an inverted five spot oattern in wnich an injection well is surrounded with four produc~ n wells, or in a line drive arrangement in which a series of aligned njection wells and a series of alignea production wells are utilize~. ~ny number of wells which may be arranged
3(}2() according to any pattern may be applied in using the present method as illustrated and described in U.S. Patent No. 3,927,716 to Burdyn et al. Either naturally occurring or artifically induced fluid communication should exist between the injection well 12 and the production well 14 in the lower part of the oil-containing formation lO. Fluid communication can be induced by techniques such as cyclic steam or solvent stimulation or fracturing of the injection well and the production well using procedures well-known in the art. This is essential to the proper functioning of our process.
Initially, a predetermined amount of a mixture of steam and 2 to 5% by volume of a light solvent having an equilibrium K-value of at least 0.5 at initial formation temperature and pressure is injected into the lower 50% or less of the formation 10 via the injection well 12 and fluids includinq oil and a portion of the light solvent are simultaneously recovered from the upper 50YO or more of the formation via the production well 14. The equilibrium K-value or vapor/liquid equilibrium constant controls the amount of solvent existing in each phase at a specified temperature and pressure and is defined as:
K = f(T,P) = Yi/Xi (1) where Yi = mole fraction of solvent i in the gas phase an~
Xi = mole fraction of solvent i in tne oil pnase.
The preferred amount of the light solvent mixed witn tne steam is 2 volume ~0 of a light solvent having an equilibrium K-value of about 1.0 at initial formation temperature and pressure. Tne preferred amount of solvent increases as tne solvent K-value decreases. The llght solvent recovered with the proaucea fluids may be in gaseous form or dissolved in the produce~ oil. The anount of steam injected into the formation is witnin tne range of 0.30 to Q.50 2() pore volume, preferably .37 Pore volume, and tne injection rate iswithin the range of 4 to 7 barrels CWE (cold water equivalent) of steam Per day per acre-foot of formation. Steam injection temperature is within the range of from 500F to 700F and quality is in tne range of about 5o% to about 90%.
Suitable light solvents include carDon dioxide and Cl to C4 hydrocarbons such as methane, ethane, ?ropane and butane.
After a predetermined amount of the mixture of steam and light solvent ~as been injected into the lower 50% or less of the formation via the injection well 12, production of fluids including oil and light solvent is continued via the pro~uction well 14 until steam ~reakthrougn occurs or until the fluid oeing produced contains a predetermined amount of water, preferaDly at least 95%.
It is postulated that the use of the mixture of steam and liqht solvent optimizes oil recovery by forming a transition region of lighter oil between tne steam zone and the heavy oil zone, creating a more favorable ~obility ratio thereby ennancing displacement efficiency, and suppressing steam channeling. Tne solvent forms a mixture region ahead of tne steam front due to its mobility and volatility and advances further into tne formation. The lignt solvent is more efficient than neavier solvents because a greater portion of tne solvent is easily recovered With tne gas pnase production. Thus, less solvent is lost Per barrel of incremental neavy oil recovered.
Tne amount of light solvent comingled with tne steam according to tne present invention results in tne qreatest efficiency of tne solvent based upon the amount of oil recovered and tne amount of solvent injected and recovered.
In another embodiment of tne invention, injection of tne mixture of stea~ and solvent may be continued and fluids including oil and solvent are produced until steam breakthrougn occurs or until the water cut of tne oroduced fluid contains at least ~5^6 water.
2() EXAMPLES
The optimized recovery realized by the disclosed invention has been demonstrated fro~ the results and analyses of a series of computer simulation runs in which the conditions of a subterranean, heavy oil-containing formation was simulated.
A heavy oil reservoir was simulated. The reservoir geometry is a 2-D vertical ~odel illustrated in Figure 2. Tne distance ~etween the in~jector and the ~roducer, ~X, was 467 feet (5-spot, 5-acre spacing). The widtn of the reservoir affected by steam, ~Y, is 80 feet. As shown in Figure 2, the reservoir was divided into six layers totaling 150 feet, the lowest layer simulating a 20 foot water zone.
The completion interval for the injector consisted of forty feet in the lower portion of tne reservoir, separated fro~ the water zone by a ten-foot distance. The completion interval for the producer consisted of tne top 80 feet of the reservoir. Tnese intervals were arrived uPon to take advantage of the steam underrunning effect caused by the water layer.
,~
2() Table 1 below summarizes the major reservoir cnaracteristics.
Temperature, F 100 Depth, ft 1445 Porosity, % 35 Average Permeability, md 6400 Kv/Kh .1 Pay Thickness, ft 130 Sw 0.39 '~ater Layer Thickness, ft 20 Sw 0.88 Oil Characteristics API ~ravity 10.9 Viscosit~, cp 55F 61,90û
255F 51.6 455F 5.31 655F 1.74 Six solvents were studie~. The neaviest was d 020-tyPe hydrocarbon witn a ~olecular weignt of 282.6. Two me~ium heavy weignt solvents were examined1 one, Solvent 4, naving tne average ~roperty of a mixture of C6, C8, C12 witn a molecular weight of 131.4, and the other, Solvent C, a lignt oil naving a molecular ~eignt of 170.3.
The liqhtest solvent, Solvent D, was a solvent naving a molecular weiqht of 44. TWQ medium weignt solvents were examined, one naving a ~olecular weiqnt of 81.5 consisting of a ~ixture of solvents ~ ano D, and the other consisting of a ~ixture of solvents C and D, an~ naving a molecular weiqnt of 95.6. ~olvent ~roperties are snown oelow in Table 2 and the e~uilibrium K-values at tei~peratures of 400F and 600F as a function of ~ressure are snown in Figure 3.
F-2524 ~9~
Medium Medium Solvent Heavy HeavY Heavy Light ~olecular ~eight282.6 170.3 131.4 44.0 (lb/lb mol) Critical Temperature 1381.0 1184.9 1067.0 665.6 (Deg. F) Oil Phase .00001 .00001 .00001 .00022 Compressibility (l/psi) Stock Tank Density 56.6 53.4 44.9 20.0 (lb/cu ft) Heat caPacity 0.6 0.5 0.6 -1.1843 +
(BTU/lb-Deg. F) .003452 (F) Viscosity (cp) 55F 20.1 1.73 2.24 .172 255F 3.14 .443 .728 .119 455F 1.25 .208 .376 .095 655F .693 .129 .240 .082 The six solvents were tested oy injecting them at varying concentrations of 2, 5, or 1~ of the steam injec~ion rate. The stea~
rate ~as 300 ST~/3, so that the solven~ ra~es varie~ from 5 to 15 to 30 a/D. These are very small amounts since only a~oul 0.37 pore volume of steam was injected. The steam quality was 0.7~, the injection temperature and pressure was 590F and 1200 psia, respectively. The solvents were injected at the same temperature and pressure conditions as the steam.
Solvent efficiency was judged according to incremental cumulative recover~J of neavy oil per barrel of solvent injected and incremental cumui-~ive recovery of heavy oil per Darrel of unrecovered solvent at steam oreakthrough. Incremental oil recovery is defined as the increase In recovering of oil using a mixture of steam and solvent as compared with using steam only.
'20 F-2524 _10-The results for all of the solvents tested are summarized in Tables 3 to 8 below including a straight steam run for comparison with runs utilizing a mixture of solvent and steam. The equilibrium K-value for each solvent at initial formation temperature and pressure is shown in Table 9 below.
Heavy ûil, M.W. = 282.6 Base Runs BSOL2 BSOL5 BSOL10 (Steam Onlv) In~jection Solvent/Steam .02 .05 .10 0 Steam (MSTB) 65.96 65.96 65.96 65.97 Solvent (STB) 1319. 3299. 6595. 0 Steam Breakthrough (Days)1000.+ 985. 952. 739.
Production (MSTB) Total Oil 25.53 21.31 21.61 26.40 Heavy Oil 25.50 21.29 21.55 25.40 Solvent .02 .02 .05 0 Water 89.03 86.12 82.97 90.36 Solvent Recovery, % 1.8 0.7 0.3 0 Incremental Cumulative -3.3 -19.4 -18.3 3 Recovery of Heavy Oil, %
Efficiency BbltBbl Inj. (1) -0.66 -1.54 -0.72 0 Bbl/Bbl Llnrecovered (2) -0.6 -1.5 -0.7 0 Note (1) Barrels of incremental heavy oil per barrel of solvent injected.
(2) aarrels of incremental heavy oil per oarrel of solvent unrecovered.
2(~
Medium Heavy Solvent, M.W. = 131.4 Base Runs ASOL2 ASOL5 ASûL10 (Steam Only) Injection Solvent/Steam .02 .05 .10 0 Steam (MSTB) 65.97 65.98 65.96 65.97 Solvent (STB) 1319. 3299. 6596. 0 Steam Breakthrough (Days) 723. 606. 497. 739.
Production (MSTB) Total Oil 30.58 38.27 43.48 26.40 Heavy Oil 30.13 36.62 39.35 26.40 Solvent .45 1.65 4.13 0 Water 91.61 88.17 86.72 90.36 Solvent Recovery, %34.1 50.0 62.6 0 Incremental Cumulative14.1 38.7 49.1 0 Recovery of Heavy Oil, %
Efficiency Bbl/Bbl Inj. 2.82 3.10 1.96 Bbl/Bbl Unrecovered4.29 6.20 5.25 0 zo Medium Heavy Solvent, M.W. = 170.3 Base Runs CSnL2 CSOL5 CSOL10 (Steam Only) Injection Solvent/Steam .02 .05 .10 0 Steam (MSTB) 65.96 65.96 65.95 65.97 Solvent (STB) 1319. 3299. 6596. o Steam Breaktnrough (Days) 765. 738. 583. 739.
Production (MSTB) Total Oil 29.33 37.43 45.62 26.40 Heavy Oil 29.14 36.52 42.47 26.40 Solvent .194 .914 3.138 Water 89.11 88.75 90.81 90.36 Solvent ~ecovery, Y~ 14.7 27.7 47.7 0 Incremental Cumulative10.4 38.3 60.9 0 Recovery of Heavy ûil, %
fficiency Bbl/Bbl Inj. 2.08 3.07 2.44 0 Bbl/3bl Unrecovered2.44 4.24 4.66 0 Me m Solvent M.'~. = 81.5 Base Runs ADSOL5 ADSOL10(Steam-Only) Injection Solvent/Steam 0.5 .1 0 Steam (MST9) 65.96 65.95 65.97 Solvent (STB) 32.98 65.96 0 Steam Breakthrough (Days)538 407 739 Production (MSTB) Total Oil 38.82 42.45 26.40 Heavy Oil 36.73 38.18 26.40 Solvent 2.09 4.27 0 Water 89.15 82.99 90.36 Solvent Recovery, c~ 63.3 64.7 0 ~ncremental Cumulative Recovery of Heavy Oil, ~39.1 44.6 0 ~fficiency Bbl/Bbl injection 3.13 1.79 0 abl/Bbl unrecovered 8.55 5.06 0 Medium Solvent ~.W = 95.6 Base Runs CDSOL5 CDSOL10 (Steam-Only) Injection Solvent/Steam 0.5 .10 0 Steam (MSTB) 65.96 65.9665.97 Solvent (ST8) 32.98 65.96 0 Steam Breakthrough (Days)574 425 739.
Production (~STB) Total Oil 39.97 41.9926.40 Heavy Oil 37.99 38.4226.40 Solvent 1.98 3.57 0 Water 93.34 84.6090.36 Solvent ~ecovery, % 60.3 54.0 0 Incremental Cumulative Recovery of Heavy Oil, %43.9 44.4 0 -fgOiCl/~on~Yiniectlon 3.51 1.82 0 Bbl/8bl unrecovered 8.79 3.97 0 Li~ht Solvent, M.W. = 44.0 Base Runs DSOL2 DSOL5 DSOLlû (Steam Only) Injection Solvent/Steam .02 .05 .10 0 Steam (MSTB) 65.95 65.96 65.96 65.97 Solvent (STB) 1319. 3298. 659G. O
Steam Breakthrough ~Days) 650. 475. 400. 739.
Production (MSTB) Total Oil 35.88 37.97 39.82 26.40 Heavy Oil 35.02 35.46 34.97 26.40 Solvent .86 2.51 4.85 0 Water 97.33 89.82 92.07 90.36 Solvent Recovery, ~65.1 76.1 73.5 0 Incremental Cumulative32.7 34.3 32.5 0 Recovery of Heavy Oil, %
~fficiency 8bl/Bbl Inj. 6.54 2.75 1.30 0 Bbl/Bbl Unrecovered18.78 11.50 4.91 0 TAaLE 9 K-Value Initial Formation Solvent Mol. Wgt. Temperature and Pressure _ Light 44.0 .937 Medium 81.5 .06 ~edium 95.6 .325 Medium Heavy 131.4 .0313 ~ledium Heavy170.3 .00011 Heavy 282.6 .000000425 v The heavy or low volatility solvent adversely affected the slug process. Cumulative oil productlon was actually decreased, and little of the solvent was recovered.
The equilibrium K-values indicate that at the temperature and 3ressure conditions within the reservoir the heavy solvent exists mostly as a liquid. r~urinq injection, solvent was observed to enter the lower water layer, increasing the oil saturation and decreasiny the water saturation. This decreased the relative permeability and thus the fractional flow of wateI as compared to the base case. The decrease in water flow decreased the flow of condensing steam horizontally into the water layer and lessened the magnitude of the underrunning hot water finger which was vital to the sweep. Steam was actually forced up in the reservoir by the entering solvent, resulting in eventual steam fingering and breakthrough in the top part of the reservoir. The sweep pattern created by these circumstances was poorer than that of tne steam-only case where a steam finger broke through the lower layer of the production well.
Another aspect of solvent coinjection is the resulting hi3her reservoir pressure than the steam-only case. The maximum pressure in the reservoir for all solvent cases is about 300 psi ~3reater than that of the base case due to additional influx of flul~. ,ince tne unconsolidated sand in the simulatecJ reservoir is hi~hly comprPssi~
the pore space increases significantly with ni;~n ore~sures. ,ii~n ne present reservoir data, the extra pressure resulting from the injection of solvent increases t~ne pore space by aDout 12.~ M~bls. If the solvent is volatile, the extra pore space may ~3e taken up oy gaseous solvent. In the case of neavy solvent, the liquid solvent couid occupy only nalf of this extra oore space. This resulted in an overall reductiJn in 3il and ~ater oisplacenent frorn the reservoir, as compared to tne steam only case.
Coinjectil~n wit~l steam of all the otner solvents en~ancecl tne steam slug 3rocess. !-~eavy 3il recovery was improvea Dy as much as ,~6. Solvent efficiency was very sirnilar for ~ne rnedium and medium .6.~1 s~
f-2524 -17-heavy solvents, with 2 to 3.5 barrels of oil recovered per barrel of solvent injected, and 4 to 8.8 barrels of oil recovered for every barrel of solvent left within the reservoir at the end of the production period.
The medium and medium heavy solvents showed a very different performance from that of the heavy solvent. This is because they nave higher K-values which increase vaporization as compared to the heavy solvent. During injection, the me~ium and medium heavy solvents travel in the gas phase before dissolving into the oil phase in the colder part of the reservoir. This results in different placement of the solvent. The condensed solvent joins the oil phase to form a buffer zone of lower viscosity between the steam and the heavy oil bank. Solvent is eventually produced from this mixture region as the steam zone grows and pushes toward the production well.
The placement of the solvent was determined very early in the injection period, and little solvent appeared in tne gas phase during most of the project life. It is therefore important that first, part of the injected solvent be vaporiza~le for a favorable placement ahead of the steam front, and second, it must also dissolve in the oil phase to alter the oil ohase characteristics and increase recovery. For Run CSOL5 (M-W- = 17û.3, injection 5% of steam) tne locations of steam, heavy oil and solvent after 4ûO days showed that the solvent is well distributed both ahead of the steam zone and tn.ou3hout the neated region behind the heavy oil bank.
The results show that the light solven~ naving an equiliorium K-value of .937 at 2~ of the steam injection rate (~un DSOL2) results in maxi~um solvent efficiency with the hi~hest amount of oil recovered Der barrel of solvent injected being 6.54 and tne highest a~ount of oil recovered per Darrel of unrecovered solvent being lB.8. At a light solvent concentration of lû percent of steam injected, Run DSOL10, oil recovery was very sligntly less than for tne runs at 2 and 5%.
The light solvent enhances the injected steam/solvent slug by forming a transition zone between the steam front and the heavy oil bank. The 2% run (DSOL2) after 400 days showed that the solvent causes a sharp, vertical interface betweerl the steam zone and solvent/heavy oil mixture region. The steam front is more perpendicular to fluid flow, resulting in a more plug flow-li~e displacement of the oil phase.
More light solvent exists in the gas phase at reservoir conditions than the medium or medium heavy solvents. Therefore, there was actually less solvent available in the oil phase to reduce the oil phase viscosity. This effect is somewhat compensated for since the light solvent is lighter and it takes less by volume tnan the medium or medium heavy solvents to have the same effect on the oil phase viscosity. The location of the steam, heavy oil and solvent after 400 days for 1~% medium heavy solvent (Run OSOL10) and 10% light solvent (Run DSCL10) show differences in the distribution of the oil phase solvent for tne light and medium heavy solvents. Also, the lighter solvent advances farther in the reservoir and exists in a more concentrated area. The medium heavy solvent is spread over a wider area and contacts more of the heavy oil, aiding recovery. Tne light solvent is more efficient tnan tne medium solvents because it is easily recovered with the gas phase production. Tnus, less solvent is lost per b~l of incremental heavy oil recovered.
Figure 4 illustrates incremental cumulative heavy oil recovered versus unrecovered solvent for all solvents ano their volumes expressed as volume % of steam except for the neavy solvent that resulted in a negative incremental cumulative oil recovery. The figure clearly shows that maximum solvent efficiency based upon the ratio of incremental cumulative oil recovered to the amount of solvent unrecovered is attained using the light solvent at 2 volume ~ of steam. Furthermore, the results show that injection of the lignt solvent a~ove 5 volume ~ of steam causes a decrease in incremental cumulative oil recovery and a significant increase in tne amount of unrecovered solvent. Thus, 5 volume % solvent/steam ratio results in maximum cumulative oil recovery versus unrecovered solvent with higher concentrations of light solvent resulting in a decrease of the ratio of cumulative oil recovered to solvent unrecovered.
By the term "pore volume" as used herein, is meant that volume of the portion of the formation underlying the well pattern employed as described in greater detail in U.S. Patent No. ~,927,716 to Burdyn et al.
Initially, a predetermined amount of a mixture of steam and 2 to 5% by volume of a light solvent having an equilibrium K-value of at least 0.5 at initial formation temperature and pressure is injected into the lower 50% or less of the formation 10 via the injection well 12 and fluids includinq oil and a portion of the light solvent are simultaneously recovered from the upper 50YO or more of the formation via the production well 14. The equilibrium K-value or vapor/liquid equilibrium constant controls the amount of solvent existing in each phase at a specified temperature and pressure and is defined as:
K = f(T,P) = Yi/Xi (1) where Yi = mole fraction of solvent i in the gas phase an~
Xi = mole fraction of solvent i in tne oil pnase.
The preferred amount of the light solvent mixed witn tne steam is 2 volume ~0 of a light solvent having an equilibrium K-value of about 1.0 at initial formation temperature and pressure. Tne preferred amount of solvent increases as tne solvent K-value decreases. The llght solvent recovered with the proaucea fluids may be in gaseous form or dissolved in the produce~ oil. The anount of steam injected into the formation is witnin tne range of 0.30 to Q.50 2() pore volume, preferably .37 Pore volume, and tne injection rate iswithin the range of 4 to 7 barrels CWE (cold water equivalent) of steam Per day per acre-foot of formation. Steam injection temperature is within the range of from 500F to 700F and quality is in tne range of about 5o% to about 90%.
Suitable light solvents include carDon dioxide and Cl to C4 hydrocarbons such as methane, ethane, ?ropane and butane.
After a predetermined amount of the mixture of steam and light solvent ~as been injected into the lower 50% or less of the formation via the injection well 12, production of fluids including oil and light solvent is continued via the pro~uction well 14 until steam ~reakthrougn occurs or until the fluid oeing produced contains a predetermined amount of water, preferaDly at least 95%.
It is postulated that the use of the mixture of steam and liqht solvent optimizes oil recovery by forming a transition region of lighter oil between tne steam zone and the heavy oil zone, creating a more favorable ~obility ratio thereby ennancing displacement efficiency, and suppressing steam channeling. Tne solvent forms a mixture region ahead of tne steam front due to its mobility and volatility and advances further into tne formation. The lignt solvent is more efficient than neavier solvents because a greater portion of tne solvent is easily recovered With tne gas pnase production. Thus, less solvent is lost Per barrel of incremental neavy oil recovered.
Tne amount of light solvent comingled with tne steam according to tne present invention results in tne qreatest efficiency of tne solvent based upon the amount of oil recovered and tne amount of solvent injected and recovered.
In another embodiment of tne invention, injection of tne mixture of stea~ and solvent may be continued and fluids including oil and solvent are produced until steam breakthrougn occurs or until the water cut of tne oroduced fluid contains at least ~5^6 water.
2() EXAMPLES
The optimized recovery realized by the disclosed invention has been demonstrated fro~ the results and analyses of a series of computer simulation runs in which the conditions of a subterranean, heavy oil-containing formation was simulated.
A heavy oil reservoir was simulated. The reservoir geometry is a 2-D vertical ~odel illustrated in Figure 2. Tne distance ~etween the in~jector and the ~roducer, ~X, was 467 feet (5-spot, 5-acre spacing). The widtn of the reservoir affected by steam, ~Y, is 80 feet. As shown in Figure 2, the reservoir was divided into six layers totaling 150 feet, the lowest layer simulating a 20 foot water zone.
The completion interval for the injector consisted of forty feet in the lower portion of tne reservoir, separated fro~ the water zone by a ten-foot distance. The completion interval for the producer consisted of tne top 80 feet of the reservoir. Tnese intervals were arrived uPon to take advantage of the steam underrunning effect caused by the water layer.
,~
2() Table 1 below summarizes the major reservoir cnaracteristics.
Temperature, F 100 Depth, ft 1445 Porosity, % 35 Average Permeability, md 6400 Kv/Kh .1 Pay Thickness, ft 130 Sw 0.39 '~ater Layer Thickness, ft 20 Sw 0.88 Oil Characteristics API ~ravity 10.9 Viscosit~, cp 55F 61,90û
255F 51.6 455F 5.31 655F 1.74 Six solvents were studie~. The neaviest was d 020-tyPe hydrocarbon witn a ~olecular weignt of 282.6. Two me~ium heavy weignt solvents were examined1 one, Solvent 4, naving tne average ~roperty of a mixture of C6, C8, C12 witn a molecular weight of 131.4, and the other, Solvent C, a lignt oil naving a molecular ~eignt of 170.3.
The liqhtest solvent, Solvent D, was a solvent naving a molecular weiqht of 44. TWQ medium weignt solvents were examined, one naving a ~olecular weiqnt of 81.5 consisting of a ~ixture of solvents ~ ano D, and the other consisting of a ~ixture of solvents C and D, an~ naving a molecular weiqnt of 95.6. ~olvent ~roperties are snown oelow in Table 2 and the e~uilibrium K-values at tei~peratures of 400F and 600F as a function of ~ressure are snown in Figure 3.
F-2524 ~9~
Medium Medium Solvent Heavy HeavY Heavy Light ~olecular ~eight282.6 170.3 131.4 44.0 (lb/lb mol) Critical Temperature 1381.0 1184.9 1067.0 665.6 (Deg. F) Oil Phase .00001 .00001 .00001 .00022 Compressibility (l/psi) Stock Tank Density 56.6 53.4 44.9 20.0 (lb/cu ft) Heat caPacity 0.6 0.5 0.6 -1.1843 +
(BTU/lb-Deg. F) .003452 (F) Viscosity (cp) 55F 20.1 1.73 2.24 .172 255F 3.14 .443 .728 .119 455F 1.25 .208 .376 .095 655F .693 .129 .240 .082 The six solvents were tested oy injecting them at varying concentrations of 2, 5, or 1~ of the steam injec~ion rate. The stea~
rate ~as 300 ST~/3, so that the solven~ ra~es varie~ from 5 to 15 to 30 a/D. These are very small amounts since only a~oul 0.37 pore volume of steam was injected. The steam quality was 0.7~, the injection temperature and pressure was 590F and 1200 psia, respectively. The solvents were injected at the same temperature and pressure conditions as the steam.
Solvent efficiency was judged according to incremental cumulative recover~J of neavy oil per barrel of solvent injected and incremental cumui-~ive recovery of heavy oil per Darrel of unrecovered solvent at steam oreakthrough. Incremental oil recovery is defined as the increase In recovering of oil using a mixture of steam and solvent as compared with using steam only.
'20 F-2524 _10-The results for all of the solvents tested are summarized in Tables 3 to 8 below including a straight steam run for comparison with runs utilizing a mixture of solvent and steam. The equilibrium K-value for each solvent at initial formation temperature and pressure is shown in Table 9 below.
Heavy ûil, M.W. = 282.6 Base Runs BSOL2 BSOL5 BSOL10 (Steam Onlv) In~jection Solvent/Steam .02 .05 .10 0 Steam (MSTB) 65.96 65.96 65.96 65.97 Solvent (STB) 1319. 3299. 6595. 0 Steam Breakthrough (Days)1000.+ 985. 952. 739.
Production (MSTB) Total Oil 25.53 21.31 21.61 26.40 Heavy Oil 25.50 21.29 21.55 25.40 Solvent .02 .02 .05 0 Water 89.03 86.12 82.97 90.36 Solvent Recovery, % 1.8 0.7 0.3 0 Incremental Cumulative -3.3 -19.4 -18.3 3 Recovery of Heavy Oil, %
Efficiency BbltBbl Inj. (1) -0.66 -1.54 -0.72 0 Bbl/Bbl Llnrecovered (2) -0.6 -1.5 -0.7 0 Note (1) Barrels of incremental heavy oil per barrel of solvent injected.
(2) aarrels of incremental heavy oil per oarrel of solvent unrecovered.
2(~
Medium Heavy Solvent, M.W. = 131.4 Base Runs ASOL2 ASOL5 ASûL10 (Steam Only) Injection Solvent/Steam .02 .05 .10 0 Steam (MSTB) 65.97 65.98 65.96 65.97 Solvent (STB) 1319. 3299. 6596. 0 Steam Breakthrough (Days) 723. 606. 497. 739.
Production (MSTB) Total Oil 30.58 38.27 43.48 26.40 Heavy Oil 30.13 36.62 39.35 26.40 Solvent .45 1.65 4.13 0 Water 91.61 88.17 86.72 90.36 Solvent Recovery, %34.1 50.0 62.6 0 Incremental Cumulative14.1 38.7 49.1 0 Recovery of Heavy Oil, %
Efficiency Bbl/Bbl Inj. 2.82 3.10 1.96 Bbl/Bbl Unrecovered4.29 6.20 5.25 0 zo Medium Heavy Solvent, M.W. = 170.3 Base Runs CSnL2 CSOL5 CSOL10 (Steam Only) Injection Solvent/Steam .02 .05 .10 0 Steam (MSTB) 65.96 65.96 65.95 65.97 Solvent (STB) 1319. 3299. 6596. o Steam Breaktnrough (Days) 765. 738. 583. 739.
Production (MSTB) Total Oil 29.33 37.43 45.62 26.40 Heavy Oil 29.14 36.52 42.47 26.40 Solvent .194 .914 3.138 Water 89.11 88.75 90.81 90.36 Solvent ~ecovery, Y~ 14.7 27.7 47.7 0 Incremental Cumulative10.4 38.3 60.9 0 Recovery of Heavy ûil, %
fficiency Bbl/Bbl Inj. 2.08 3.07 2.44 0 Bbl/3bl Unrecovered2.44 4.24 4.66 0 Me m Solvent M.'~. = 81.5 Base Runs ADSOL5 ADSOL10(Steam-Only) Injection Solvent/Steam 0.5 .1 0 Steam (MST9) 65.96 65.95 65.97 Solvent (STB) 32.98 65.96 0 Steam Breakthrough (Days)538 407 739 Production (MSTB) Total Oil 38.82 42.45 26.40 Heavy Oil 36.73 38.18 26.40 Solvent 2.09 4.27 0 Water 89.15 82.99 90.36 Solvent Recovery, c~ 63.3 64.7 0 ~ncremental Cumulative Recovery of Heavy Oil, ~39.1 44.6 0 ~fficiency Bbl/Bbl injection 3.13 1.79 0 abl/Bbl unrecovered 8.55 5.06 0 Medium Solvent ~.W = 95.6 Base Runs CDSOL5 CDSOL10 (Steam-Only) Injection Solvent/Steam 0.5 .10 0 Steam (MSTB) 65.96 65.9665.97 Solvent (ST8) 32.98 65.96 0 Steam Breakthrough (Days)574 425 739.
Production (~STB) Total Oil 39.97 41.9926.40 Heavy Oil 37.99 38.4226.40 Solvent 1.98 3.57 0 Water 93.34 84.6090.36 Solvent ~ecovery, % 60.3 54.0 0 Incremental Cumulative Recovery of Heavy Oil, %43.9 44.4 0 -fgOiCl/~on~Yiniectlon 3.51 1.82 0 Bbl/8bl unrecovered 8.79 3.97 0 Li~ht Solvent, M.W. = 44.0 Base Runs DSOL2 DSOL5 DSOLlû (Steam Only) Injection Solvent/Steam .02 .05 .10 0 Steam (MSTB) 65.95 65.96 65.96 65.97 Solvent (STB) 1319. 3298. 659G. O
Steam Breakthrough ~Days) 650. 475. 400. 739.
Production (MSTB) Total Oil 35.88 37.97 39.82 26.40 Heavy Oil 35.02 35.46 34.97 26.40 Solvent .86 2.51 4.85 0 Water 97.33 89.82 92.07 90.36 Solvent Recovery, ~65.1 76.1 73.5 0 Incremental Cumulative32.7 34.3 32.5 0 Recovery of Heavy Oil, %
~fficiency 8bl/Bbl Inj. 6.54 2.75 1.30 0 Bbl/Bbl Unrecovered18.78 11.50 4.91 0 TAaLE 9 K-Value Initial Formation Solvent Mol. Wgt. Temperature and Pressure _ Light 44.0 .937 Medium 81.5 .06 ~edium 95.6 .325 Medium Heavy 131.4 .0313 ~ledium Heavy170.3 .00011 Heavy 282.6 .000000425 v The heavy or low volatility solvent adversely affected the slug process. Cumulative oil productlon was actually decreased, and little of the solvent was recovered.
The equilibrium K-values indicate that at the temperature and 3ressure conditions within the reservoir the heavy solvent exists mostly as a liquid. r~urinq injection, solvent was observed to enter the lower water layer, increasing the oil saturation and decreasiny the water saturation. This decreased the relative permeability and thus the fractional flow of wateI as compared to the base case. The decrease in water flow decreased the flow of condensing steam horizontally into the water layer and lessened the magnitude of the underrunning hot water finger which was vital to the sweep. Steam was actually forced up in the reservoir by the entering solvent, resulting in eventual steam fingering and breakthrough in the top part of the reservoir. The sweep pattern created by these circumstances was poorer than that of tne steam-only case where a steam finger broke through the lower layer of the production well.
Another aspect of solvent coinjection is the resulting hi3her reservoir pressure than the steam-only case. The maximum pressure in the reservoir for all solvent cases is about 300 psi ~3reater than that of the base case due to additional influx of flul~. ,ince tne unconsolidated sand in the simulatecJ reservoir is hi~hly comprPssi~
the pore space increases significantly with ni;~n ore~sures. ,ii~n ne present reservoir data, the extra pressure resulting from the injection of solvent increases t~ne pore space by aDout 12.~ M~bls. If the solvent is volatile, the extra pore space may ~3e taken up oy gaseous solvent. In the case of neavy solvent, the liquid solvent couid occupy only nalf of this extra oore space. This resulted in an overall reductiJn in 3il and ~ater oisplacenent frorn the reservoir, as compared to tne steam only case.
Coinjectil~n wit~l steam of all the otner solvents en~ancecl tne steam slug 3rocess. !-~eavy 3il recovery was improvea Dy as much as ,~6. Solvent efficiency was very sirnilar for ~ne rnedium and medium .6.~1 s~
f-2524 -17-heavy solvents, with 2 to 3.5 barrels of oil recovered per barrel of solvent injected, and 4 to 8.8 barrels of oil recovered for every barrel of solvent left within the reservoir at the end of the production period.
The medium and medium heavy solvents showed a very different performance from that of the heavy solvent. This is because they nave higher K-values which increase vaporization as compared to the heavy solvent. During injection, the me~ium and medium heavy solvents travel in the gas phase before dissolving into the oil phase in the colder part of the reservoir. This results in different placement of the solvent. The condensed solvent joins the oil phase to form a buffer zone of lower viscosity between the steam and the heavy oil bank. Solvent is eventually produced from this mixture region as the steam zone grows and pushes toward the production well.
The placement of the solvent was determined very early in the injection period, and little solvent appeared in tne gas phase during most of the project life. It is therefore important that first, part of the injected solvent be vaporiza~le for a favorable placement ahead of the steam front, and second, it must also dissolve in the oil phase to alter the oil ohase characteristics and increase recovery. For Run CSOL5 (M-W- = 17û.3, injection 5% of steam) tne locations of steam, heavy oil and solvent after 4ûO days showed that the solvent is well distributed both ahead of the steam zone and tn.ou3hout the neated region behind the heavy oil bank.
The results show that the light solven~ naving an equiliorium K-value of .937 at 2~ of the steam injection rate (~un DSOL2) results in maxi~um solvent efficiency with the hi~hest amount of oil recovered Der barrel of solvent injected being 6.54 and tne highest a~ount of oil recovered per Darrel of unrecovered solvent being lB.8. At a light solvent concentration of lû percent of steam injected, Run DSOL10, oil recovery was very sligntly less than for tne runs at 2 and 5%.
The light solvent enhances the injected steam/solvent slug by forming a transition zone between the steam front and the heavy oil bank. The 2% run (DSOL2) after 400 days showed that the solvent causes a sharp, vertical interface betweerl the steam zone and solvent/heavy oil mixture region. The steam front is more perpendicular to fluid flow, resulting in a more plug flow-li~e displacement of the oil phase.
More light solvent exists in the gas phase at reservoir conditions than the medium or medium heavy solvents. Therefore, there was actually less solvent available in the oil phase to reduce the oil phase viscosity. This effect is somewhat compensated for since the light solvent is lighter and it takes less by volume tnan the medium or medium heavy solvents to have the same effect on the oil phase viscosity. The location of the steam, heavy oil and solvent after 400 days for 1~% medium heavy solvent (Run OSOL10) and 10% light solvent (Run DSCL10) show differences in the distribution of the oil phase solvent for tne light and medium heavy solvents. Also, the lighter solvent advances farther in the reservoir and exists in a more concentrated area. The medium heavy solvent is spread over a wider area and contacts more of the heavy oil, aiding recovery. Tne light solvent is more efficient tnan tne medium solvents because it is easily recovered with the gas phase production. Tnus, less solvent is lost per b~l of incremental heavy oil recovered.
Figure 4 illustrates incremental cumulative heavy oil recovered versus unrecovered solvent for all solvents ano their volumes expressed as volume % of steam except for the neavy solvent that resulted in a negative incremental cumulative oil recovery. The figure clearly shows that maximum solvent efficiency based upon the ratio of incremental cumulative oil recovered to the amount of solvent unrecovered is attained using the light solvent at 2 volume ~ of steam. Furthermore, the results show that injection of the lignt solvent a~ove 5 volume ~ of steam causes a decrease in incremental cumulative oil recovery and a significant increase in tne amount of unrecovered solvent. Thus, 5 volume % solvent/steam ratio results in maximum cumulative oil recovery versus unrecovered solvent with higher concentrations of light solvent resulting in a decrease of the ratio of cumulative oil recovered to solvent unrecovered.
By the term "pore volume" as used herein, is meant that volume of the portion of the formation underlying the well pattern employed as described in greater detail in U.S. Patent No. ~,927,716 to Burdyn et al.
Claims (8)
1. A method for recovering viscous oil from a subterranean, viscous oil-containing formation including a tar sand deposit, said formation being penetrated by at least one injection well in fluid communication with only the lower 50% or less of the oil-containing formation and by at least one spaced-apart production well in fluid communication with only the upper 50% of the oil-containing formation, comprising:
(a) injecting into the formation via the injection well a predetermined amount of a mixture of steam and 2 to 5%
by volume of a light solvent having an equilibrium K-value of at least 0.5 at initial formation temperature and pressure to maximize solvent efficiency and simultaneously recovering fluids including oil and a portion of the light solvent from the formation via the production well; and (b) continuing to recover fluids including oil and light solvent from the formation via the production well until steam breakthrough occurs or until the fluid being recovered from the production well comprises at least 95% of water.
(a) injecting into the formation via the injection well a predetermined amount of a mixture of steam and 2 to 5%
by volume of a light solvent having an equilibrium K-value of at least 0.5 at initial formation temperature and pressure to maximize solvent efficiency and simultaneously recovering fluids including oil and a portion of the light solvent from the formation via the production well; and (b) continuing to recover fluids including oil and light solvent from the formation via the production well until steam breakthrough occurs or until the fluid being recovered from the production well comprises at least 95% of water.
2. The method of Claim 1 wherein the concentration of light solvent in the steam-solvent mixture is about 2% by volume and the solvent equilibrium K-value is about 1.0 at initial formation temperature and pressure.
3. The method of Claim 2 wherein the steam has a temperature within the range of 500°F to 700°F and a quality within the range of 50 to 90%.
4. The method of Claim 3 wherein the amount of steam injected during step (a) is within the range of 0.30 to 0.50 pore volume.
5. The method of Claim 4 wherein the light solvent comprises C1 to C4 hydrocarbons and carbon dioxide.
6. The method of Claim 5 wherein the steam injection rate is within the range of 4 to 7 barrels (CWE) of steam per day per acre-foot of formation.
7. The method of Claim 1 further comprising continuing injecting steam and solvent into the injection well and producing fluids from the production well until steam breakthrough occurs or until the producing fluid contains a predetermined amount of water.
8. The method of Claim 6 wherein the C1-C4 hydrocarbons are methane, ethane, propane or butane.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US55392483A | 1983-11-21 | 1983-11-21 | |
| US553,924 | 1983-11-21 |
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| Publication Number | Publication Date |
|---|---|
| CA1228020A true CA1228020A (en) | 1987-10-13 |
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| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000467976A Expired CA1228020A (en) | 1983-11-21 | 1984-11-16 | Solvent assisted steam injection process for recovery of viscous oil |
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Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US8770288B2 (en) | 2010-03-18 | 2014-07-08 | Exxonmobil Upstream Research Company | Deep steam injection systems and methods |
| CN114814175A (en) * | 2021-01-28 | 2022-07-29 | 中国石油天然气股份有限公司 | Three-dimensional simulation experiment device and method for foam oil |
-
1984
- 1984-11-16 CA CA000467976A patent/CA1228020A/en not_active Expired
Cited By (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US8770288B2 (en) | 2010-03-18 | 2014-07-08 | Exxonmobil Upstream Research Company | Deep steam injection systems and methods |
| CN114814175A (en) * | 2021-01-28 | 2022-07-29 | 中国石油天然气股份有限公司 | Three-dimensional simulation experiment device and method for foam oil |
| CN114814175B (en) * | 2021-01-28 | 2024-04-30 | 中国石油天然气股份有限公司 | Foam oil three-dimensional simulation experiment device and method |
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