CA1059432A - Hydrocarbon recovery - Google Patents
Hydrocarbon recoveryInfo
- Publication number
- CA1059432A CA1059432A CA268,740A CA268740A CA1059432A CA 1059432 A CA1059432 A CA 1059432A CA 268740 A CA268740 A CA 268740A CA 1059432 A CA1059432 A CA 1059432A
- Authority
- CA
- Canada
- Prior art keywords
- gas
- pressure
- oil sand
- temperature
- hydrocarbon
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired
Links
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/164—Injecting CO2 or carbonated water
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
- E21B43/168—Injecting a gaseous medium
Abstract
Abstract of the Disclosure The viscosity of heavy hydrocarbons in oil sand is substantially reduced by disolving solvent gases, e.g. CO2 and ethane, in the hydrocarbons at the ambient temperature and at pressures above, equal to or slightly less than the liquefaction pressure of the solvent gas. This allows removal of the hydro-carbons from an oil sand deposit under the action of a driving force such as gravity, differential gas pressure, or a displacement medium e.g. water.
Description
The present invention relates to methods for fluidi-fying heavy hydrocarbons present in oil sand material, whereby the high-visco~ity hydrocarbons may be recovered. of chief interest for the purpo~e of the invention is the oil sand found in Alberta. This oil sand contains high-viscosity hydrocarbons cf high average molecular weight, typically in excess of about 600 or 700, in intimate admixture with finely divided, solid, inorganic particles and other impurities, often together with substantial amounts of water and quantities of natural gases.
Deposits of comparable minerals containing high-viscosity, heavy hydrocarbons are also found in other localities, and as with the Albertan oil sand, recovery of hydrocarbons from deposits of the~e minerals through a well by normal petroleum recovery methods i8 difficult or impracticable. The term "oil sand materials" is to be understood to include all such minerals.
In the natural state, and especially where the deposits are underground, these oil sand materials exist at low temperatures.
In large areas of the underground Alberta oil sand deposits, for example, ths underground temperature i8 usually around 40F. At these temperature~ the hydrocarbons have a thick, semi-solid con~istency and they are substantially immobile.
Prior proposals for recovering hydrocarbons from such materials have largely relied on applying heat to the oil sand so that the hydrocarbons become less viscous and can be made to flow. However, the heating operation expends an unduly high proportion of the recoverable energy.
It has now been found that a considerable reduction in the viscosity of the hydrocarbon, often to a point where the hydrocarbon flows like water, can be obtained without needing to heat the oil sand material, by contacting the material with a pressurised solvent gas at a temperature below its critical temperature and not substantially above the ambient temperature of the material, and under a pressure close to and not substantially above the saturation vapour pressure at the temperature of the oil sand material. When a pure gas is employed, the most rapid viscosity reductions are obtained when the gas is at a pressure equal to, or slightly less than the saturation vapour pressure of the gas at the ambient temperature.
10 At these conditions, the gas will be close to the liquid state, and in the preferred form the pure gas is applied at a pressure such that at the temperature of the oil sand material the solvent gas will be in the gaseous state but close to the line of transition between the gaseous and liquid state.
When mixtures of gases containing one or more solvent gases are employed, it is not necessary for the partial pressure of the solvent gas to be close to or above the saturation vapour pressure at the oil sand temperature. In such a case, however, when a rapid viscosity reduction is obtained it has been 20 observed that the total pressure of the gas mixture is not substantially less than the saturation vapour pressure of the solvent gas at the temperature of the oil sand material.
By the term "solvent gas" we refer to normally gaseous materials which are miscible with and dissolve in naturally-occurring high-viscosity hydrocarbons. Examples include carbon s dioxide, the lower alkanes e.g. methane, ethane, propane, etc., and alkenes such as ethylene, propylene, and the isomeric butenes. Of these, carbon dioxide and ethane are preferred.
Carbon dioxide is generally available at reasonably low cost and ethane may be . ._
Deposits of comparable minerals containing high-viscosity, heavy hydrocarbons are also found in other localities, and as with the Albertan oil sand, recovery of hydrocarbons from deposits of the~e minerals through a well by normal petroleum recovery methods i8 difficult or impracticable. The term "oil sand materials" is to be understood to include all such minerals.
In the natural state, and especially where the deposits are underground, these oil sand materials exist at low temperatures.
In large areas of the underground Alberta oil sand deposits, for example, ths underground temperature i8 usually around 40F. At these temperature~ the hydrocarbons have a thick, semi-solid con~istency and they are substantially immobile.
Prior proposals for recovering hydrocarbons from such materials have largely relied on applying heat to the oil sand so that the hydrocarbons become less viscous and can be made to flow. However, the heating operation expends an unduly high proportion of the recoverable energy.
It has now been found that a considerable reduction in the viscosity of the hydrocarbon, often to a point where the hydrocarbon flows like water, can be obtained without needing to heat the oil sand material, by contacting the material with a pressurised solvent gas at a temperature below its critical temperature and not substantially above the ambient temperature of the material, and under a pressure close to and not substantially above the saturation vapour pressure at the temperature of the oil sand material. When a pure gas is employed, the most rapid viscosity reductions are obtained when the gas is at a pressure equal to, or slightly less than the saturation vapour pressure of the gas at the ambient temperature.
10 At these conditions, the gas will be close to the liquid state, and in the preferred form the pure gas is applied at a pressure such that at the temperature of the oil sand material the solvent gas will be in the gaseous state but close to the line of transition between the gaseous and liquid state.
When mixtures of gases containing one or more solvent gases are employed, it is not necessary for the partial pressure of the solvent gas to be close to or above the saturation vapour pressure at the oil sand temperature. In such a case, however, when a rapid viscosity reduction is obtained it has been 20 observed that the total pressure of the gas mixture is not substantially less than the saturation vapour pressure of the solvent gas at the temperature of the oil sand material.
By the term "solvent gas" we refer to normally gaseous materials which are miscible with and dissolve in naturally-occurring high-viscosity hydrocarbons. Examples include carbon s dioxide, the lower alkanes e.g. methane, ethane, propane, etc., and alkenes such as ethylene, propylene, and the isomeric butenes. Of these, carbon dioxide and ethane are preferred.
Carbon dioxide is generally available at reasonably low cost and ethane may be . ._
- 2 -~ ~Q5943Z
available at low cost depending on the refining processes sub-sequently applied to the recovered hydroc æbon. Both of these gases have excellent viscosity-reducing effects. Under the more usual temperature conditions, the critical temperature of methane is exceeded and so it is impossible to bring methane close to the liquefaction point. Thus, the use of methane is in most circumstances inconvenient.
The higher molecular weight of alkanes higher than ethane can be disadvantageous since the degree of viscosity reduction depends on the molar concentration of the dissolved gas in the hydrocarbon, and moreover, as the higher alkanes condense easily to a liquid, large amounts of the gas will tend to condense out as a liquid during injection into uhderground deposits, because of the low initial temperature of the deposits, without coming into effective contact with the hydrocarbons contained in the deposits.
In the preforred practice, the solvent gases applied to the oil sand consist substantially wholly of carbon dioxide, ethane, or mixture of carbon dioxide and ethane. These solvent gases may be diluted with other gases such as methane, propane, butane, and liquefied petroleum gas mixtures but greater total quantities of gas may then have to be applied for more prolonged periods in order to obtain a comparable fluidity of the hydro-carbon, and in the preferred form the gas applied to the oil sand material contains at least 10% by volume of ethane or carbon dioxide.
In the normal practice of this invention, the solvent gases are contacted with the oil sand material at ambient A temperatures normally in the range of 400F to 85F, and under a .
, ` 105943Z
pressure suitable for the oil sand material to be treated, until the viscosity of the hydrocarbon is reduced to the point where the hydrocarbon is flowable. The solvent gas should be at a pressure not less than about 95% of the saturation vapour pressure of the gas at the temperature of the oil sand. At pressures substantially less than the saturation vapour pressure at deposit temperatures, the effects of the solvent gas may be much slower than when the gas pressure is raised to close to the liquefaction point. The applied pressure of the solvent gas is controlled so that it is not substantially above the saturation vapour pressure at the relevant temperature, so that the process is conducted substantially without any formation of a liquefied solvent gas phase, as this results in the condensation underground of larger amounts of gas than are required for adequate viscosity reduction. The reduced-viscosity hydrocarbon can be withdrawn as a fluid from the oil sand under pressure sufficient to maintain the content of the dissolved gas in the hydrocarbon. The recovered hydro- ;
carbon may then be treated to separate the dissolved gases, which can be recycled.
This method may be applied to oil sand in its native state either in underground deposits or at the surface to mined material.
In the treatment of oil sand above ground, the method can be applied directly to the mineral material at ambient temperature and under quiescent conditions without needing to preheat or comminute the material. In the treatment of mined material it is, however, necessary to confine the material within pressure vessels capable of withstanding the applied - 4 ~
..
pressure of the solvent gases, while in in situ underground operation, the natural deposit pressures or the relatively low porosity of the oil sand due to its hydrocarbon content can serve to confine the solvents and maintain the required pressures.
In underground treatments, a single or multiple well boring may ~e employed. A single well may serve both as an injection well and a production well. The solvent gases are - 4a -- ~ .
~05943Z
initially in~ected under high pressure for a period of time, which in most cases extends to several days or weeks, sufficent to fluidify an extensive volume of the hydrocarbon. Thereafter, production through the well may be commenced, the pressure at the well head being controlled so as to be at a sufficiently high level to maintain in the produced hydrocarbon a concentration of dissolved solvent gases adequate to preserve the low-viscosity fluid state of the hydrocarbon. In the treatment of certain ~ -deposits it may be necessary to employ a deep well pump to main-tain adequate pressure on the hydrocarbon in its upward delivery path.
In the preferred practice, however, mutually distant injection and production wells are employed. An example is shown in the accompanying drawings.
Figure 1 illustrates in schematic form an example of the practice o~ this invention applied to an underground oil sand deposit.
Figures 2, 3, and 4 are graphs plotting visco~ity against timo or a heavy hydrocarbon in contact with pressurised solvent gases.
Referring to Figure 1, an oil sand deposit 1, or other comparable deposit, i8 penetrated by an injection well 2 and a production well 3, both extending deeply into the deposit. A gas storage tank 4 containing liquid solvent ga~ is connected to the injection well through a steam-heated heat exchanger 6, having a steam inlet 7, and through a line 8 connecting the heat exchanger 6 to the injection well. A pump 9 is also provided, connectable directly between the well and the tank 4 through a line 11, whereby liquid gas can be ~upplied direct to the well 2.
An outlet line 12 connects the production well head to _5_ a pressure controller 13 and a flash evaporator 14. The evaporator 14 is heated by a steam line 15. The evaporator 14 has outlets 16 and 17 for evaporated solvent gas and for the hydrocarbon residue, respectively.
Provision is made for recycling the separated solvent gas through a cooling heat exchanger 18, a compressor and inter-cooler 19, and a further cooling heat exchanger 21, each having cooling water inlets and outlets 22 and 23.
In starting-up the recovery operation, the solvent gas is initially passed to the injection well with the production well clo~ed. The solvent gas may be supplied in the gaseous form from the heat exchanger 6 or directly from the compressor 19 through a line 24,-or in the liquid form pumped by the pump 9 from the storage tank 4. The supply is continued until an extensive under-ground volume of the hydrocarbon has been permeated and saturated with the solvent. The initial injection period may last for several day~. Thereafter, with the injection of solvent gas through well 2 continuing, the production well is opened to allow outflow of the fluidified hydrocarbon through the line 12. In production, the pressure in the line 12 is controlled by regulation of the pressure controller 13 so as to maintain an adequate viqcosity-reducing content of dissolved gas in the produced hydro-carbon. where the vertical rise to the surface is great, a deep well pump in the production well can be employed to maintain the required pressure on the fluidified hydrocarbon and prevent the evolution of gas in the pipe line with consequent substantial viscosity increase.
Where the underground pressure is inadequate to propel the hydrocarbon from the depo~it, a displacement medium, e.g. a displacement water drive or other inert fluid drive may be used to move the hydrocarbon to the production well.
. ~ : . , .
In order to facilitate the initial permeation of thesolvent gases into the underground formation~, and to speed the flow of the fluidified hydrocarbons underground, it is normally preferred to establish a pervious or increased porosity under-ground communication path between the injection and production wells before commencing the injection of the solvent gas. This can be readily accomplished by conventional procedure~, e.g.
hydraulic fracturing.
The production of low-viscosity hydrocarbon is delivered to the flash evaporator 14 where, after preheating typically to a temperature of about 150 to 200F, the hydrocarbon is rapidly depressurised, and under the heating supplied from the steam line 15 the solvent gas is flashed off to the line 16. The hydrocarbon i8 heated within the evaporator so that it is maintained in a flowable state and is withdrawn from the production outlet 17 as refinable product.
The recycled gas is compre~sed and cooled to the injection temperature and passed to the injection well 2 along line 24.
Altornatively, all or part of the separated ga~ is cooled and is liquofied at the heat exchanger 21 and returned to the storage 4.
An auxiliary supply of the solvent gas is fed as necessary from a further solvent gas storage tank 25, to make up for any gas losses from the system.
In typical operating conditions, the oil sand or other viscous hydrocarbon deposit may lie beneath an overburden of depth -;
in the range of from several hundred feet to several thousand feet.
of the known A~berta oil sand depo-~its, for example, over 90~ lies deeper than 200 feet. Such deposits exist at temperature~ greatly less than 85F, typically less than about 60F, and temperatures of about 40F are mo~t usual.
... . .
The natural or applied deposit pressures may range up to about 1000 psia depending on their depth and at these pressures, the viscosity of the hydrocarbon can be reduced by dissolution of the solvent gas to the point where the applied pressure is adequate to propel it from the injection well to the production well. In some instances, however, a driving force of increased pressure over the natural pressure may have to be applied to cause the hydrocarbon to flow.
When the solvent gases are injected through the injection well in the gaseous form at pressures and temperatures such that they are close to the liquefaction point, once equilibrium conditions are reached the gases dissolve in the hydrocarbon direct from the gaseous form. However, until equilibrium conditions are reached, in the initial injection and at relatively cooler regions of the underground deposit, the solvent gases can condense as a liquid on cooler mineral material in the underground formation. As a result of release of latent heat, the mineral material becomes warmed as the solvent gas condenses, and under continuing injection the gas will pass through the underground deposit and effect a vigorous dissolving or condensing action on fresh areas of the deposit.
In this manner, the possibility of the solvent gases by-passing the hydrocarbon and flowing directly to the production well as free gas can be reduced. By way of an example, it can be mentioned that in the case of underground deposits at temperatures of about 40F to about 85F, a typical solvent gas such as ethane or carbon dioxide may be supplied in a state close to its liquefaction point at temperatures less than the critical temperature of from about 40F and 85F and at corresponding pressures of from about 385 psia to 648 psia in the case of ethane and 570 psia to 1000 psia in the case of carbon dioxide, the gas ~ ~ .....
105943Z :: -conden~ing out as a liquid on contact with the cooler mineral material. In this manner, the condensed gas is brought into intLmate dissolving contact with the mineral material, and -increased operating efficiency is obtained, without any, or any significant amount of, free gas being produced at the production well. As a result of the underground condensation of the gases, the underground deposits will be warmed, thus contributing further to the viscosity reduction of the hydrocarbon.
Some natural gas may be recovered along with the fluidiæed hydrocarbon withdrawn from the production well, and -the recovered gas can be recycled to the system, thus at lea~t partially compensating for gases lost underground and avoiding or reducing the need to make up for gas losses by feeding auxiliary solvent gas to the system.
In examples of typical conditions, the solvent gases supplied through the injection well 1 may be at 250F to 90F
and at a pressure of 500 psia to 1000 psia. The hydrocarbon recovered through the line 12 from the production well 2 may bo at 300F to 60F and a pre~sure in the range of 400 to 1000 psia. In separating the solvent gases at the flaqh evaporator, the hydrocarbon may be raised to temperature~ in the range of 150F to 200F, prior to and ~ubsequent to the pressure being reduced to 0 to 55 psia.
Figures 2 to 4 illustrate examples of the viscosity roductions that can be obtained by applying the solvent gases to a bituminous hydrocarbon obtained as an extract from oil sand material.
The hydrocarbon was maintained in a pressure ves~el cooled to below room temperature, the so1vent gase~ being contacted with the hydrocarbon at the pressures indicated and _g_ : , at a temperature of about 57F in the example of Figure 2, 50F for Figure 3 and about 540F for Figure 4. The viscosities were compared at intervals over the periods indicated by recording the amperage demand drawn by a constant-voltage motor for driving an agitator immersed in the hydro-carbon at a given speed.
It should be noted that under the conditions of Figure 2, the ethane is under pressure greater than its ~aturation vapour pressure at the temperature of the hydro-carbon.
By way of comparison Figure 2 also shows theviscosities obtained when the hydrocarbon is heated to elevated tempePature, and also the viscosity with the agitator immersed in water.
Figure 3 shows as a comparison the viscosity of the hydrocarbon heated to 54.8-C and also the viscosity value obtained with the agitator in water. under the conditions of pressure of 500 to 510 psig of Figure 3, the carbon dioxide is at a state just outside the liquidus of the carbon dioxide phase diagram, i.e. it i8 under a pressure slightly less than its saturation vapour pressure at the temperature of the hydrocarbon.
In Figure 4, pure compressed methane was applied initially, and at the temperature of the hydrocarbon, the methane is above its critical temperature. As can be seen, only a very slow rate of viscosity reduction was obtained. on - -introducing C02 in a quantity to give an approximately 90% CH4, 10% C02 volume mixture, the viscosity immediately dropped sharply to a value comparable with the viscosity of water.
The partial pressure of the C02 is considerably less than its saturation vapour pressure at the temperature of the hydro-carbon. It will be observed that the total gas pressure is greater than the saturation vapour pressure of C02 at this temperature.
In an example cf viscosity reduction using ethane at pressures lower than those employed in Figure 2, a sample of the hydrocarbon was ~ooled to ~2-F and ethane at a pressure of 325 psig was contacted with the hydrocarbon. In measurements of the agitator amperage demand, the amperage continued to fall 10 by 18% during the period from 10 min~tes after the addition of ~ -the ethane until 21 minutes after the addition of the ethane.
Under the conditions of this example the ethane pressure is approximately 6% fielow its saturation vapour pressure at 420P.
In three further examples, in order to further demonstrate the fluidification which is achieved, oil sands were treated with carbon dioxide or ethane at pressures in equilibrium with the respective liquefied gases at the temperatures concerned.
Firstly, a sample of Albertan oil sand was compacted over a porous bed of inert particulate material and was subjected isostatically to a pressure 0~ from 725 to 865 psig of C02 for 101 hours at temperature~ in the range 66 to 72F. Fluidified ~!.
bitumen flowed from the oil sand into the porous bed. The porous bed was then separated from the sample and weighed. 29 per cent of the bitumen originally present in the sample had flowed into the porous bed.
When the same procedure was followed using a small quantity of water placed on top of the oil sand sample 80 as to tend to displace the fluidified bitumen by its own weight, it was found that 40~ of the bitumen originally present had passed into :, . . . . .
'' ."' .''. ' ' ' . ' . '." ~ . ',' ~: ' -- 105~432 the porous bed.
When the same procedure was followed using ethane at pressures of 515 to 535 psig, about 55% of the bitumen migrated out of the sample by gravity without water being used as a displacement medium.
available at low cost depending on the refining processes sub-sequently applied to the recovered hydroc æbon. Both of these gases have excellent viscosity-reducing effects. Under the more usual temperature conditions, the critical temperature of methane is exceeded and so it is impossible to bring methane close to the liquefaction point. Thus, the use of methane is in most circumstances inconvenient.
The higher molecular weight of alkanes higher than ethane can be disadvantageous since the degree of viscosity reduction depends on the molar concentration of the dissolved gas in the hydrocarbon, and moreover, as the higher alkanes condense easily to a liquid, large amounts of the gas will tend to condense out as a liquid during injection into uhderground deposits, because of the low initial temperature of the deposits, without coming into effective contact with the hydrocarbons contained in the deposits.
In the preforred practice, the solvent gases applied to the oil sand consist substantially wholly of carbon dioxide, ethane, or mixture of carbon dioxide and ethane. These solvent gases may be diluted with other gases such as methane, propane, butane, and liquefied petroleum gas mixtures but greater total quantities of gas may then have to be applied for more prolonged periods in order to obtain a comparable fluidity of the hydro-carbon, and in the preferred form the gas applied to the oil sand material contains at least 10% by volume of ethane or carbon dioxide.
In the normal practice of this invention, the solvent gases are contacted with the oil sand material at ambient A temperatures normally in the range of 400F to 85F, and under a .
, ` 105943Z
pressure suitable for the oil sand material to be treated, until the viscosity of the hydrocarbon is reduced to the point where the hydrocarbon is flowable. The solvent gas should be at a pressure not less than about 95% of the saturation vapour pressure of the gas at the temperature of the oil sand. At pressures substantially less than the saturation vapour pressure at deposit temperatures, the effects of the solvent gas may be much slower than when the gas pressure is raised to close to the liquefaction point. The applied pressure of the solvent gas is controlled so that it is not substantially above the saturation vapour pressure at the relevant temperature, so that the process is conducted substantially without any formation of a liquefied solvent gas phase, as this results in the condensation underground of larger amounts of gas than are required for adequate viscosity reduction. The reduced-viscosity hydrocarbon can be withdrawn as a fluid from the oil sand under pressure sufficient to maintain the content of the dissolved gas in the hydrocarbon. The recovered hydro- ;
carbon may then be treated to separate the dissolved gases, which can be recycled.
This method may be applied to oil sand in its native state either in underground deposits or at the surface to mined material.
In the treatment of oil sand above ground, the method can be applied directly to the mineral material at ambient temperature and under quiescent conditions without needing to preheat or comminute the material. In the treatment of mined material it is, however, necessary to confine the material within pressure vessels capable of withstanding the applied - 4 ~
..
pressure of the solvent gases, while in in situ underground operation, the natural deposit pressures or the relatively low porosity of the oil sand due to its hydrocarbon content can serve to confine the solvents and maintain the required pressures.
In underground treatments, a single or multiple well boring may ~e employed. A single well may serve both as an injection well and a production well. The solvent gases are - 4a -- ~ .
~05943Z
initially in~ected under high pressure for a period of time, which in most cases extends to several days or weeks, sufficent to fluidify an extensive volume of the hydrocarbon. Thereafter, production through the well may be commenced, the pressure at the well head being controlled so as to be at a sufficiently high level to maintain in the produced hydrocarbon a concentration of dissolved solvent gases adequate to preserve the low-viscosity fluid state of the hydrocarbon. In the treatment of certain ~ -deposits it may be necessary to employ a deep well pump to main-tain adequate pressure on the hydrocarbon in its upward delivery path.
In the preferred practice, however, mutually distant injection and production wells are employed. An example is shown in the accompanying drawings.
Figure 1 illustrates in schematic form an example of the practice o~ this invention applied to an underground oil sand deposit.
Figures 2, 3, and 4 are graphs plotting visco~ity against timo or a heavy hydrocarbon in contact with pressurised solvent gases.
Referring to Figure 1, an oil sand deposit 1, or other comparable deposit, i8 penetrated by an injection well 2 and a production well 3, both extending deeply into the deposit. A gas storage tank 4 containing liquid solvent ga~ is connected to the injection well through a steam-heated heat exchanger 6, having a steam inlet 7, and through a line 8 connecting the heat exchanger 6 to the injection well. A pump 9 is also provided, connectable directly between the well and the tank 4 through a line 11, whereby liquid gas can be ~upplied direct to the well 2.
An outlet line 12 connects the production well head to _5_ a pressure controller 13 and a flash evaporator 14. The evaporator 14 is heated by a steam line 15. The evaporator 14 has outlets 16 and 17 for evaporated solvent gas and for the hydrocarbon residue, respectively.
Provision is made for recycling the separated solvent gas through a cooling heat exchanger 18, a compressor and inter-cooler 19, and a further cooling heat exchanger 21, each having cooling water inlets and outlets 22 and 23.
In starting-up the recovery operation, the solvent gas is initially passed to the injection well with the production well clo~ed. The solvent gas may be supplied in the gaseous form from the heat exchanger 6 or directly from the compressor 19 through a line 24,-or in the liquid form pumped by the pump 9 from the storage tank 4. The supply is continued until an extensive under-ground volume of the hydrocarbon has been permeated and saturated with the solvent. The initial injection period may last for several day~. Thereafter, with the injection of solvent gas through well 2 continuing, the production well is opened to allow outflow of the fluidified hydrocarbon through the line 12. In production, the pressure in the line 12 is controlled by regulation of the pressure controller 13 so as to maintain an adequate viqcosity-reducing content of dissolved gas in the produced hydro-carbon. where the vertical rise to the surface is great, a deep well pump in the production well can be employed to maintain the required pressure on the fluidified hydrocarbon and prevent the evolution of gas in the pipe line with consequent substantial viscosity increase.
Where the underground pressure is inadequate to propel the hydrocarbon from the depo~it, a displacement medium, e.g. a displacement water drive or other inert fluid drive may be used to move the hydrocarbon to the production well.
. ~ : . , .
In order to facilitate the initial permeation of thesolvent gases into the underground formation~, and to speed the flow of the fluidified hydrocarbons underground, it is normally preferred to establish a pervious or increased porosity under-ground communication path between the injection and production wells before commencing the injection of the solvent gas. This can be readily accomplished by conventional procedure~, e.g.
hydraulic fracturing.
The production of low-viscosity hydrocarbon is delivered to the flash evaporator 14 where, after preheating typically to a temperature of about 150 to 200F, the hydrocarbon is rapidly depressurised, and under the heating supplied from the steam line 15 the solvent gas is flashed off to the line 16. The hydrocarbon i8 heated within the evaporator so that it is maintained in a flowable state and is withdrawn from the production outlet 17 as refinable product.
The recycled gas is compre~sed and cooled to the injection temperature and passed to the injection well 2 along line 24.
Altornatively, all or part of the separated ga~ is cooled and is liquofied at the heat exchanger 21 and returned to the storage 4.
An auxiliary supply of the solvent gas is fed as necessary from a further solvent gas storage tank 25, to make up for any gas losses from the system.
In typical operating conditions, the oil sand or other viscous hydrocarbon deposit may lie beneath an overburden of depth -;
in the range of from several hundred feet to several thousand feet.
of the known A~berta oil sand depo-~its, for example, over 90~ lies deeper than 200 feet. Such deposits exist at temperature~ greatly less than 85F, typically less than about 60F, and temperatures of about 40F are mo~t usual.
... . .
The natural or applied deposit pressures may range up to about 1000 psia depending on their depth and at these pressures, the viscosity of the hydrocarbon can be reduced by dissolution of the solvent gas to the point where the applied pressure is adequate to propel it from the injection well to the production well. In some instances, however, a driving force of increased pressure over the natural pressure may have to be applied to cause the hydrocarbon to flow.
When the solvent gases are injected through the injection well in the gaseous form at pressures and temperatures such that they are close to the liquefaction point, once equilibrium conditions are reached the gases dissolve in the hydrocarbon direct from the gaseous form. However, until equilibrium conditions are reached, in the initial injection and at relatively cooler regions of the underground deposit, the solvent gases can condense as a liquid on cooler mineral material in the underground formation. As a result of release of latent heat, the mineral material becomes warmed as the solvent gas condenses, and under continuing injection the gas will pass through the underground deposit and effect a vigorous dissolving or condensing action on fresh areas of the deposit.
In this manner, the possibility of the solvent gases by-passing the hydrocarbon and flowing directly to the production well as free gas can be reduced. By way of an example, it can be mentioned that in the case of underground deposits at temperatures of about 40F to about 85F, a typical solvent gas such as ethane or carbon dioxide may be supplied in a state close to its liquefaction point at temperatures less than the critical temperature of from about 40F and 85F and at corresponding pressures of from about 385 psia to 648 psia in the case of ethane and 570 psia to 1000 psia in the case of carbon dioxide, the gas ~ ~ .....
105943Z :: -conden~ing out as a liquid on contact with the cooler mineral material. In this manner, the condensed gas is brought into intLmate dissolving contact with the mineral material, and -increased operating efficiency is obtained, without any, or any significant amount of, free gas being produced at the production well. As a result of the underground condensation of the gases, the underground deposits will be warmed, thus contributing further to the viscosity reduction of the hydrocarbon.
Some natural gas may be recovered along with the fluidiæed hydrocarbon withdrawn from the production well, and -the recovered gas can be recycled to the system, thus at lea~t partially compensating for gases lost underground and avoiding or reducing the need to make up for gas losses by feeding auxiliary solvent gas to the system.
In examples of typical conditions, the solvent gases supplied through the injection well 1 may be at 250F to 90F
and at a pressure of 500 psia to 1000 psia. The hydrocarbon recovered through the line 12 from the production well 2 may bo at 300F to 60F and a pre~sure in the range of 400 to 1000 psia. In separating the solvent gases at the flaqh evaporator, the hydrocarbon may be raised to temperature~ in the range of 150F to 200F, prior to and ~ubsequent to the pressure being reduced to 0 to 55 psia.
Figures 2 to 4 illustrate examples of the viscosity roductions that can be obtained by applying the solvent gases to a bituminous hydrocarbon obtained as an extract from oil sand material.
The hydrocarbon was maintained in a pressure ves~el cooled to below room temperature, the so1vent gase~ being contacted with the hydrocarbon at the pressures indicated and _g_ : , at a temperature of about 57F in the example of Figure 2, 50F for Figure 3 and about 540F for Figure 4. The viscosities were compared at intervals over the periods indicated by recording the amperage demand drawn by a constant-voltage motor for driving an agitator immersed in the hydro-carbon at a given speed.
It should be noted that under the conditions of Figure 2, the ethane is under pressure greater than its ~aturation vapour pressure at the temperature of the hydro-carbon.
By way of comparison Figure 2 also shows theviscosities obtained when the hydrocarbon is heated to elevated tempePature, and also the viscosity with the agitator immersed in water.
Figure 3 shows as a comparison the viscosity of the hydrocarbon heated to 54.8-C and also the viscosity value obtained with the agitator in water. under the conditions of pressure of 500 to 510 psig of Figure 3, the carbon dioxide is at a state just outside the liquidus of the carbon dioxide phase diagram, i.e. it i8 under a pressure slightly less than its saturation vapour pressure at the temperature of the hydrocarbon.
In Figure 4, pure compressed methane was applied initially, and at the temperature of the hydrocarbon, the methane is above its critical temperature. As can be seen, only a very slow rate of viscosity reduction was obtained. on - -introducing C02 in a quantity to give an approximately 90% CH4, 10% C02 volume mixture, the viscosity immediately dropped sharply to a value comparable with the viscosity of water.
The partial pressure of the C02 is considerably less than its saturation vapour pressure at the temperature of the hydro-carbon. It will be observed that the total gas pressure is greater than the saturation vapour pressure of C02 at this temperature.
In an example cf viscosity reduction using ethane at pressures lower than those employed in Figure 2, a sample of the hydrocarbon was ~ooled to ~2-F and ethane at a pressure of 325 psig was contacted with the hydrocarbon. In measurements of the agitator amperage demand, the amperage continued to fall 10 by 18% during the period from 10 min~tes after the addition of ~ -the ethane until 21 minutes after the addition of the ethane.
Under the conditions of this example the ethane pressure is approximately 6% fielow its saturation vapour pressure at 420P.
In three further examples, in order to further demonstrate the fluidification which is achieved, oil sands were treated with carbon dioxide or ethane at pressures in equilibrium with the respective liquefied gases at the temperatures concerned.
Firstly, a sample of Albertan oil sand was compacted over a porous bed of inert particulate material and was subjected isostatically to a pressure 0~ from 725 to 865 psig of C02 for 101 hours at temperature~ in the range 66 to 72F. Fluidified ~!.
bitumen flowed from the oil sand into the porous bed. The porous bed was then separated from the sample and weighed. 29 per cent of the bitumen originally present in the sample had flowed into the porous bed.
When the same procedure was followed using a small quantity of water placed on top of the oil sand sample 80 as to tend to displace the fluidified bitumen by its own weight, it was found that 40~ of the bitumen originally present had passed into :, . . . . .
'' ."' .''. ' ' ' . ' . '." ~ . ',' ~: ' -- 105~432 the porous bed.
When the same procedure was followed using ethane at pressures of 515 to 535 psig, about 55% of the bitumen migrated out of the sample by gravity without water being used as a displacement medium.
Claims (14)
PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:
1. A method of fluidifying a heavy hydrocarbon present in a naturally-occurring oil sand material comprising contacting the material with a pressurised solvent gas, the material existing at a temperature less than the critical temperature of the gas, the gas being capable of dissolving in the hydro-carbon and being at a temperature below its critical temperature and not substantially above the ambient temperature of the material, and being supplied to the oil sand material under a pressure not less than about 95% of its saturation vapour pressure and not substantially more than its saturation vapour pressure at the temperature of the oil sand material.
2. A method as claimed in claim 1 in which the solvent gas is applied as a pure gas.
3. A method as claimed in claim 1 wherein the solvent gas is contained in a gas mixture and is applied at a partial pressure above, below or equal to its saturation vapour pressure and at a total gas mixture pressure not substantially less than the saturation vapour pressure of the solvent gas contained therein.
4. A method as claimed in claim 1 wherein the solvent gas is injected directly into an underground deposit of the oil sand material.
5. A method as claimed in claim 1 wherein the solvent gas is contacted with mined oil sand material at the surface at a temperature not exceeding normal atmospheric temperature.
6. A method as claimed in claim 1 including the further steps of withdrawing fluidified bituminous hydrocarbon from the oil sand material while maintaining a pressure on the hydrocarbon sufficient to maintain a viscosity-reducing content of the dissolved solvent gas therein, and thereafter separating the dissolved gas from the hydrocarbon.
7. A method as claimed in claim 6 including the step of re-cycling separated gas to the oil sand material.
8. A method as claimed in claim 2 wherein the solvent gas is ethane.
9. A method as claimed in claim 2 wherein the solvent gas is carbon dioxide.
10. A method as claimed in claim 3 wherein the gas mixture contains at least 10 per cent by volume of ethane or carbon dioxide as the solvent gas.
11. A method as claimed in claim 1 wherein ethane is contacted with the oil sand material at a pressure of up to about 700 psig and a temperature of up to about the critical temperature of ethane.
12. A method as claimed in claim 1 wherein carbon dioxide is contacted with the oil sand material at a pressure up to about 1050 psig and a temperature up to about the critical temperature of carbon dioxide.
13. A method as claimed in claim 4 in which the solvent gas is injected into the deposit in the gaseous form at a pressure close to its liquefaction pressure when at the temperature of the deposit, so that the injected gas will tend to condense to a liquid within the deposit.
14. A method as claimed in claim 6 or 7 in which the fluidified hydrocarbon is displaced from the oil sand material by water or other displacement media.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA268,740A CA1059432A (en) | 1976-12-24 | 1976-12-24 | Hydrocarbon recovery |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA268,740A CA1059432A (en) | 1976-12-24 | 1976-12-24 | Hydrocarbon recovery |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1059432A true CA1059432A (en) | 1979-07-31 |
Family
ID=4107590
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA268,740A Expired CA1059432A (en) | 1976-12-24 | 1976-12-24 | Hydrocarbon recovery |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA1059432A (en) |
Cited By (22)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US6662872B2 (en) | 2000-11-10 | 2003-12-16 | Exxonmobil Upstream Research Company | Combined steam and vapor extraction process (SAVEX) for in situ bitumen and heavy oil production |
| US6708759B2 (en) | 2001-04-04 | 2004-03-23 | Exxonmobil Upstream Research Company | Liquid addition to steam for enhancing recovery of cyclic steam stimulation or LASER-CSS |
| US6769486B2 (en) | 2001-05-31 | 2004-08-03 | Exxonmobil Upstream Research Company | Cyclic solvent process for in-situ bitumen and heavy oil production |
| US6883607B2 (en) | 2001-06-21 | 2005-04-26 | N-Solv Corporation | Method and apparatus for stimulating heavy oil production |
| US7527096B2 (en) | 2005-01-26 | 2009-05-05 | Nexen Inc. | Methods of improving heavy oil production |
| US8596357B2 (en) | 2006-06-07 | 2013-12-03 | John Nenniger | Methods and apparatuses for SAGD hydrocarbon production |
| US8602098B2 (en) | 2010-02-16 | 2013-12-10 | Exxonmobil Upstream Research Company | Hydrate control in a cyclic solvent-dominated hydrocarbon recovery process |
| US8607884B2 (en) | 2010-01-29 | 2013-12-17 | Conocophillips Company | Processes of recovering reserves with steam and carbon dioxide injection |
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| US8752623B2 (en) | 2010-02-17 | 2014-06-17 | Exxonmobil Upstream Research Company | Solvent separation in a solvent-dominated recovery process |
| US8776900B2 (en) | 2006-07-19 | 2014-07-15 | John Nenniger | Methods and apparatuses for enhanced in situ hydrocarbon production |
| US8788250B2 (en) | 2007-05-24 | 2014-07-22 | Exxonmobil Upstream Research Company | Method of improved reservoir simulation of fingering systems |
| WO2014177188A1 (en) * | 2013-04-30 | 2014-11-06 | Statoil Canada Limited | Method of recovering thermal energy |
| US8899321B2 (en) | 2010-05-26 | 2014-12-02 | Exxonmobil Upstream Research Company | Method of distributing a viscosity reducing solvent to a set of wells |
| US9488040B2 (en) | 2013-12-03 | 2016-11-08 | Exxonmobil Upstream Research Company | Cyclic solvent hydrocarbon recovery process using an advance-retreat movement of the injectant |
| US10041340B2 (en) | 2013-12-19 | 2018-08-07 | Exxonmobil Upstream Research Company | Recovery from a hydrocarbon reservoir by conducting an exothermic reaction to produce a solvent and injecting the solvent into a hydrocarbon reservoir |
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-
1976
- 1976-12-24 CA CA268,740A patent/CA1059432A/en not_active Expired
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|---|---|---|---|---|
| US6662872B2 (en) | 2000-11-10 | 2003-12-16 | Exxonmobil Upstream Research Company | Combined steam and vapor extraction process (SAVEX) for in situ bitumen and heavy oil production |
| US6708759B2 (en) | 2001-04-04 | 2004-03-23 | Exxonmobil Upstream Research Company | Liquid addition to steam for enhancing recovery of cyclic steam stimulation or LASER-CSS |
| US6769486B2 (en) | 2001-05-31 | 2004-08-03 | Exxonmobil Upstream Research Company | Cyclic solvent process for in-situ bitumen and heavy oil production |
| US6883607B2 (en) | 2001-06-21 | 2005-04-26 | N-Solv Corporation | Method and apparatus for stimulating heavy oil production |
| US7363973B2 (en) | 2001-06-21 | 2008-04-29 | N Solv Corp | Method and apparatus for stimulating heavy oil production |
| US7527096B2 (en) | 2005-01-26 | 2009-05-05 | Nexen Inc. | Methods of improving heavy oil production |
| US7717175B2 (en) | 2005-01-26 | 2010-05-18 | Nexen Inc. | Methods of improving heavy oil production |
| US8596357B2 (en) | 2006-06-07 | 2013-12-03 | John Nenniger | Methods and apparatuses for SAGD hydrocarbon production |
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| US8788250B2 (en) | 2007-05-24 | 2014-07-22 | Exxonmobil Upstream Research Company | Method of improved reservoir simulation of fingering systems |
| US8607884B2 (en) | 2010-01-29 | 2013-12-17 | Conocophillips Company | Processes of recovering reserves with steam and carbon dioxide injection |
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| US8752623B2 (en) | 2010-02-17 | 2014-06-17 | Exxonmobil Upstream Research Company | Solvent separation in a solvent-dominated recovery process |
| US8684079B2 (en) | 2010-03-16 | 2014-04-01 | Exxonmobile Upstream Research Company | Use of a solvent and emulsion for in situ oil recovery |
| US8899321B2 (en) | 2010-05-26 | 2014-12-02 | Exxonmobil Upstream Research Company | Method of distributing a viscosity reducing solvent to a set of wells |
| US10669827B2 (en) | 2011-06-28 | 2020-06-02 | Conocophilips Company | Recycling CO2 in heavy oil or bitumen production |
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