CA2917260A1 - Accelerated solvent-aided sagd start-up - Google Patents
Accelerated solvent-aided sagd start-up Download PDFInfo
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- CA2917260A1 CA2917260A1 CA2917260A CA2917260A CA2917260A1 CA 2917260 A1 CA2917260 A1 CA 2917260A1 CA 2917260 A CA2917260 A CA 2917260A CA 2917260 A CA2917260 A CA 2917260A CA 2917260 A1 CA2917260 A1 CA 2917260A1
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- steam
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- 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
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
- E21B43/2406—Steam assisted gravity drainage [SAGD]
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- 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
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
- E21B43/2406—Steam assisted gravity drainage [SAGD]
- E21B43/2408—SAGD in combination with other methods
Abstract
Disclosed herein is a method and system for improving the recovery of hydrocarbons from a reservoir. The method includes injecting a steam-solvent mixture at during the start-up phase of a gravity-assisted recovery process, such as a SAGD operation. Using the method disclosed, oil and solvent production rates can be increased while decreasing the steam requirements for the SAGD operation when the solvent-steam mixture is injected prior to substantial inter-well communication being established.
Description
ACCELERATED SOLVENT-AIDED SAGD START-UP
FIELD
This relates generally to methods and systems for enhancing hydrocarbon recovery through solvent addition in SAGD operations.
BACKGROUND
Steam-Assisted Gravity Drainage (SAGD) is an enhanced oil recovery teclmology for producing heavy crude oil and bitumen. However, in spite of its success in recovering highly viscous bitumen, SAGD remains an expensive technique that requires large energy input in the form of steam for each barrel of produced oil. This entails consuming large quantities of water and natural gas, resulting in considerable greenhouse gas emissions and costly post-production water treatment procedures.
Many modifications to SAGD continue to evolve to achieve higher energy efficiency and environmental sustainability while maintaining economic viability. Such efforts include the use of solvents along with steam to reduce bitumen viscosity simultaneously through thermal diffusion and dilution. However, many of these techniques still suffer from poor efficiencies due to, for example, the use of excessive amounts of solvent, the need to use excessive amounts of steam, losses of solvent, failure to achieve a suitable steam to oil ratio, etc. Thus, methods to improve SAUD efficiency are sought after in the industry.
SUIVIIVIARY
As solvent and steam costs contribute significantly to the overall costs of a SAGD
operation, there is a major impetus to find ways to maximize the efficacy of a SAGD
operation. In a typical SAGD operation, steam must be circulated within a viscous bitumen reservoir to reduce the viscosity of bitumen such that the mobilized bitumen can be recovered from the production well. As there is no oil being produced during this so-called circulation phase or start-up phase, it would be beneficial to reduce the time of the start-up phase. Moreover, optimization of a SAGD operation by reducing steam consumption has the potential to reduce greenhouse gas (GEIG) emissions while making SAGD more energy efficient and cost-effective. The methods described herein are directed at shortening the time of the start-up phase of a SAGD operation.
This invention relates generally to methods and systems for injecting solvent during the early phase (e.g. during the "start-up phase") of a SAGD or SAGD-related operation.
Normally, during the start-up phase of a SAGD operation, the injection and production wells are heated by steam circulation to reduce the viscosity of the oil (which is generally in the form of bitumen) in the inter-well zone and to establish fluid communication between the injection and the production wells. Generally, when steam alone is injected during the start-up phase, it takes around 3-6 months to establish inter-well communication, depending on the reservoir and injection conditions, among other factors. Once the viscosity in the inter-well region is between approximately 6004200 cp (cp¨ centipoise), then the bitumen may be sufficiently mobilized to allow it to flow and
FIELD
This relates generally to methods and systems for enhancing hydrocarbon recovery through solvent addition in SAGD operations.
BACKGROUND
Steam-Assisted Gravity Drainage (SAGD) is an enhanced oil recovery teclmology for producing heavy crude oil and bitumen. However, in spite of its success in recovering highly viscous bitumen, SAGD remains an expensive technique that requires large energy input in the form of steam for each barrel of produced oil. This entails consuming large quantities of water and natural gas, resulting in considerable greenhouse gas emissions and costly post-production water treatment procedures.
Many modifications to SAGD continue to evolve to achieve higher energy efficiency and environmental sustainability while maintaining economic viability. Such efforts include the use of solvents along with steam to reduce bitumen viscosity simultaneously through thermal diffusion and dilution. However, many of these techniques still suffer from poor efficiencies due to, for example, the use of excessive amounts of solvent, the need to use excessive amounts of steam, losses of solvent, failure to achieve a suitable steam to oil ratio, etc. Thus, methods to improve SAUD efficiency are sought after in the industry.
SUIVIIVIARY
As solvent and steam costs contribute significantly to the overall costs of a SAGD
operation, there is a major impetus to find ways to maximize the efficacy of a SAGD
operation. In a typical SAGD operation, steam must be circulated within a viscous bitumen reservoir to reduce the viscosity of bitumen such that the mobilized bitumen can be recovered from the production well. As there is no oil being produced during this so-called circulation phase or start-up phase, it would be beneficial to reduce the time of the start-up phase. Moreover, optimization of a SAGD operation by reducing steam consumption has the potential to reduce greenhouse gas (GEIG) emissions while making SAGD more energy efficient and cost-effective. The methods described herein are directed at shortening the time of the start-up phase of a SAGD operation.
This invention relates generally to methods and systems for injecting solvent during the early phase (e.g. during the "start-up phase") of a SAGD or SAGD-related operation.
Normally, during the start-up phase of a SAGD operation, the injection and production wells are heated by steam circulation to reduce the viscosity of the oil (which is generally in the form of bitumen) in the inter-well zone and to establish fluid communication between the injection and the production wells. Generally, when steam alone is injected during the start-up phase, it takes around 3-6 months to establish inter-well communication, depending on the reservoir and injection conditions, among other factors. Once the viscosity in the inter-well region is between approximately 6004200 cp (cp¨ centipoise), then the bitumen may be sufficiently mobilized to allow it to flow and
2 subsequent stages of the SAGD operation, such as ramp-up, can begin. The injection of steam and solvent together during the start-up phase of a SAGD operation accelerates the establishment of fluid communication between the injection and production wells in viscous hydrocarbon-containing formation of limited fluid mobility. The earliest possible establishment of inter-well communication in turn allows for better overall performance of a SAGD operation.
In one aspect there is provided a method for recovering hydrocarbons from a reservoir, such as a low mobility reservoir. The reservoir is intersected by one or more horizontal wells, referred to as injection wells and production wells that are spaced apart vertically.
A steam-solvent mixture may be injected into the injection well when there is no substantial inter-well fluid communication between the injection well and the production well placed vertically below it. The steam-solvent mixture is circulated for a time sufficient for the bitumen in the inter-well region to be mobilized. Mobilized hydrocarbons can then be recovered from the production well.
In one embodiment, after the initial solvent-steam injection, circulation may be discontinued for a period of time, before further injection of either steam alone or a mixture of steam-solvent is resumed. In another embodiment, a steam-solvent mixture may be injected into both the injection well and the production well during start-up.
According to another aspect, there is provided a method of recovering hydrocarbons from a subterranean formation, the method comprising injecting a first steam-solvent mixture
In one aspect there is provided a method for recovering hydrocarbons from a reservoir, such as a low mobility reservoir. The reservoir is intersected by one or more horizontal wells, referred to as injection wells and production wells that are spaced apart vertically.
A steam-solvent mixture may be injected into the injection well when there is no substantial inter-well fluid communication between the injection well and the production well placed vertically below it. The steam-solvent mixture is circulated for a time sufficient for the bitumen in the inter-well region to be mobilized. Mobilized hydrocarbons can then be recovered from the production well.
In one embodiment, after the initial solvent-steam injection, circulation may be discontinued for a period of time, before further injection of either steam alone or a mixture of steam-solvent is resumed. In another embodiment, a steam-solvent mixture may be injected into both the injection well and the production well during start-up.
According to another aspect, there is provided a method of recovering hydrocarbons from a subterranean formation, the method comprising injecting a first steam-solvent mixture
3 into an injection well during the start-up phase of a SAGD operation for a time sufficient to establish inter-well communication, discontinuing injection of the first steam-solvent mixture, injecting a second steam-solvent mixture into the injection well, wherein the solvent in the first steam-solvent mixture has a greater proportion of heavy hydrocarbons or is a heavier solvent compared to the solvent in the second steam-solvent mixture, and recovering hydrocarbons from the production well. Generally, the first steam-solvent mixture will be injected during the start-up phase of the SAGD operation, and the second steam-solvent mixture will be injected sometime after at least some inter-well communication between the injection well and the production well has been established.
It will be appreciated that the steam-solvent mixtures may also be injected into the production well during the start-up phase. It will also be appreciated that there may be additional steam-solvents mixtures injected either during start-up or later during the SAGD operation, either intermittently with steam alone or consecutively with each other and that the various steam-solvent mixtures may have different compositions, as dictated by the SAGD operation or the phase of the SAGD operation.
According to one aspect, there is a method for establishing inter-well communication in a viscous hydrocarbon-containing formation, the method comprising injecting a first steam-solvent mixture into an injection well while simultaneously injecting a second steam-solvent mixture into a production well, the solvent in the second steam-solvent mixture comprising a higher proportion of light hydrocarbons or a lighter solvent compared to the solvent in the first steam-solvent mixture, In one embodiment, there may be a third steam-solvent mixture injected into either the injection well, the production well or both,
It will be appreciated that the steam-solvent mixtures may also be injected into the production well during the start-up phase. It will also be appreciated that there may be additional steam-solvents mixtures injected either during start-up or later during the SAGD operation, either intermittently with steam alone or consecutively with each other and that the various steam-solvent mixtures may have different compositions, as dictated by the SAGD operation or the phase of the SAGD operation.
According to one aspect, there is a method for establishing inter-well communication in a viscous hydrocarbon-containing formation, the method comprising injecting a first steam-solvent mixture into an injection well while simultaneously injecting a second steam-solvent mixture into a production well, the solvent in the second steam-solvent mixture comprising a higher proportion of light hydrocarbons or a lighter solvent compared to the solvent in the first steam-solvent mixture, In one embodiment, there may be a third steam-solvent mixture injected into either the injection well, the production well or both,
4
5 the third steam-solvent mixture having a higher proportion of light hydrocarbons compared to the first and second steam-solvent mixtures and that the third steam-solvent mixture may be added during the start-up phase or at a later phase of the SAGD
Operation.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 illustrates a conventional steam assisted gravity drainage system, FIG. 2 shows a graph of cumulative oil production versus cumulative injected steam when various concentrations of cracked naphtha are injected into a model system according to one embodiment.
FIG. 3 shows a graph of oil drainage rate versus time when various concentations of cracked naphtha are injected into a model system according to one embodiment.
FIG. 4 shows a graph of cumulative oil production versus cumulative injected steam when various concentrations of gas condensate are injected into a model system according to one embodiment.
FIG. 5 shows a graph of oil drainage rate versus time when various concentrations of gas condensate are injected into a model system according to one embodiment, DETAILED DESCRIPTION
In the following detailed description section, specific embodiments of the present techniques are described. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the techniques are not limited to the specific embodiments described below, but rather, include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.
Definitions For purposes of consistency, the following terins have the following meanings:
"Heavy oil includes oils which are classified by the American Petroleum Institute (API), as heavy oils, extra heavy oils, or bitumens. "Heavy oil" includes asphaltic, dense (low API gravity), and viscous oil that is chemically characterized by its content of asphaltenes. Although variously defined, the limits for heavy oils have been set at API
gravity of 22 or lower and a viscosity of more than 100 cP. Once the viscosity of heavy oils is decreased for example by using steam-based processes, their inability increases.
Once the hydrocarbons are mobilized, they can be recovered using substantially gravity-controlled processes.
Operation.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 illustrates a conventional steam assisted gravity drainage system, FIG. 2 shows a graph of cumulative oil production versus cumulative injected steam when various concentrations of cracked naphtha are injected into a model system according to one embodiment.
FIG. 3 shows a graph of oil drainage rate versus time when various concentations of cracked naphtha are injected into a model system according to one embodiment.
FIG. 4 shows a graph of cumulative oil production versus cumulative injected steam when various concentrations of gas condensate are injected into a model system according to one embodiment.
FIG. 5 shows a graph of oil drainage rate versus time when various concentrations of gas condensate are injected into a model system according to one embodiment, DETAILED DESCRIPTION
In the following detailed description section, specific embodiments of the present techniques are described. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the techniques are not limited to the specific embodiments described below, but rather, include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.
Definitions For purposes of consistency, the following terins have the following meanings:
"Heavy oil includes oils which are classified by the American Petroleum Institute (API), as heavy oils, extra heavy oils, or bitumens. "Heavy oil" includes asphaltic, dense (low API gravity), and viscous oil that is chemically characterized by its content of asphaltenes. Although variously defined, the limits for heavy oils have been set at API
gravity of 22 or lower and a viscosity of more than 100 cP. Once the viscosity of heavy oils is decreased for example by using steam-based processes, their inability increases.
Once the hydrocarbons are mobilized, they can be recovered using substantially gravity-controlled processes.
6 "Bitumen" is a naturally occurring heavy oil material. Generally, bitumen is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes, Bitumen is mined and recovered from oil sands deposits in, for example, the Athabasca area of Alberta and in countries such as Venezuela.
"Cyclic recovery process" or "cyclic process" refers to the steam and/or steam/solvent mixture and/or steam/solvent/gas mixture being injected into a reservoir on a periodic or intermittent basis. For example, injections may be altered depending on the extent or recovery. It is also noted that for any SAGD process, there may be multiple mechanisms, in addition to gravity drainage, that contribute to recovery, and that the inventions described herein are not intended to be limited to recovery processes that are based entirely on gravity drainage.
"Intermittent injection" refers to a process wherein either steam alone, solvent alone, or a steam-solvent mixture can be injected and then, injection can be stopped for a period of time before being resumed and that when injection is resumed, either steam alone, solvent alone, or a steam-solvent mixture can be injected. This invention relates to the timing of solvent addition during a SAGD operation, and it is contemplated that solvent addition will occur during the start-up phase of a SAGO operation. As such, variations wherein steam is first injected, wherein solvent is injected alone, wherein solvent is
"Cyclic recovery process" or "cyclic process" refers to the steam and/or steam/solvent mixture and/or steam/solvent/gas mixture being injected into a reservoir on a periodic or intermittent basis. For example, injections may be altered depending on the extent or recovery. It is also noted that for any SAGD process, there may be multiple mechanisms, in addition to gravity drainage, that contribute to recovery, and that the inventions described herein are not intended to be limited to recovery processes that are based entirely on gravity drainage.
"Intermittent injection" refers to a process wherein either steam alone, solvent alone, or a steam-solvent mixture can be injected and then, injection can be stopped for a period of time before being resumed and that when injection is resumed, either steam alone, solvent alone, or a steam-solvent mixture can be injected. This invention relates to the timing of solvent addition during a SAGD operation, and it is contemplated that solvent addition will occur during the start-up phase of a SAGO operation. As such, variations wherein steam is first injected, wherein solvent is injected alone, wherein solvent is
7 injected as a steam-solvent mixture (e.g. co-injection), and wherein solvent may also be injected at a later stage of a SAGD operation, are all included within the scope of this invention, provided that solvent addition occurs at least during the start-up phase of the SAGD operation.
"Start-up" phase of a SAGD operation refers to the start or initiation of a SAGD
operation. During the start-up phase, substantial inter-well communication has been not been established. Thus, the hydrocarbons in the reservoir are not yet mobile.
Also, during the start-up phase, steam chamber growth is initiated, but there is little or no substantial steam chamber formed per se. In the prior art literature, the "start-up" phase of a SAGD
operation may also be referred to as the circulation phase. For purposes of this disclosure, the terms "start-up phase" and "circulation phase" are intended to have the same meaning and this disclosure is intended to any process for which solvent is added early in the SAGD operation, before inter-well communication has been established and at least before the time that production of hydrocarbons has occurred.
As used throughout this disclosure, the volume of solvent or "vol%" solvent refers to the volume of solvent per total steam plus solvent volume on a cold liquid equivalent basis.
"Solvent co-injection with steam" (SCIS) refers to a variation of SAGD wherein solvent is co-injected with steam to mobilize bitumen through simultaneous heat and mass transfer processes, As used throughout this disclosure, SCIS means a SAGD
operation in which solvent is added along with steam.
"Viscous hydrocarbon-containing formation" means a subterranean formation containing oils of high viscosity and which are largely incapable of being recovered without the use of heat or dilution. An example of a viscous hydrocarbon-containing formation is an oil sands reservoir with bitumen.
Many commercial SAGD processes involve various stages of operations. These stages are sometimes classified as start-up, ramp-up, conventional or normal SAGD and blow-down operations. Each of these phases is described briefly below.
Conventionally, the start-up phase of a SAGD operation is performed to establish thermal and hydraulic communication between SAGD injection and production wells.
Initially, the reservoir contains cold bitumen of high viscosity and limited mobility so that there is no fluid communication between the injection and production wells. The start-up phase may include circulating steam through one or both the injection and production wells, thereby establishing inter-well communication. The time required to establish fluid communication is reservoir and well-pair dependent, but relates to factors such as injector-to-producer well separation along the horizontal well length, injected steam temperatures and reservoir pressures at which circulation is maintained.
Typical steam circulation time is around 120 days, but may be shorter or longer. Once inter-well conununication is established, well pairs can be transitioned to the ramp-up phase of the SAGD operation.
The ramp-up phase of a SAGD operation generally refers to a period of time after conununication has been established between the SAGD injection and production wells.
The steam chamber has already been established, and grows vertically up to the top of the bitumen zone, Mobilized oil and water are removed from the production well.
The entire length of the well pair eventually becomes heated and oil production rates peak.
Conventional or normal SAGD operation refers to the phase after the ramp-up phase.
During this phase, the steam chamber has essentially reached almost maximum vertical height and continues to extend laterally. The oil production rates are steady or possibly start to decline.
Blow-down operations refers to a phase wherein steam injection is terminated and often, a non-condensable gas in injected into the steam chamber to maintain pressure, Oil production rates decline over time and eventually the operation becomes uneconomic.
Thereafter, the SAGD well pairs may be abandoned, The present invention relates to methods and systems for enhancing the recovery of hydrocarbons such as heavy oil through solvent injection during the initial or so-called start-up phase of SAGD and SAGD-related operations, Using the same amount of steam, solvent injection with steam during the start-up phase of a SAGD operation (e.g. before substantial inter-well fluid communication has been established between the injection well and the production well) increases oil recovery and reduces cumulative steam-to-oil ratio (SOR) relative to a SAGD operation in which there has been no solvent addition during the start-up phase of SAGD.
The addition of solvent early in a SAGD operation (e.g. during the start-up phase of SAGD and/or at least before substantial inter-well communication has been established) accelerates the mobilization of bitumen in the inter-well region, and promotes the rapid formation of a steam chamber. The ability to establish good inter-well communication during the start-up phase shortens the time to transition to the ramp-up phase and allows for a more efficient SAGD operation (e.g. earlier peak oil production, decreased SOR, etc.). Once good communication is established, there is continued development and growth of the steam chamber, and the entirety of the SAGD operation is enhanced.
Establishing good communication early on in a SAGD operation allows for better ramp-up and better overall SAGD performance. The time required to switch between the start-up phase of a SAGD operation to the ramp-up phase of a SAGD-mode of operation is diminished when solvent is added during the start-up phase of a SAGD
operation. The more rapid and/or enhanced mobilization of bitumen is due to the combined effects of conduction and dilution by solvent on viscosity of the bitumen in the inter-well zone, and all of these effects are particularly pronounced when solvent is injected as early as possible in the SAGD operation.
Further, the use of solvent with steam during the start-up phase of SAGD
allows for more uniform fluid development along the length of the wells, This OCCUrs because of greater dilution of bitumen by solvent along the well segments heated to lower temperatures.
Thus, the timing of solvent injection is important in determining how to optimize the overall efficacy of a SAGD operation. In many prior art studies, the timing of solvent injection is not injected during the start-up phase of the SAGD operation and/or the solvent is only injected sometime after at least some inter-well communication has been established. Also, in many prior art studies, solvent is added late as after peak oil production rates have been observed. This invention differs from these prior studies in that solvent co-injection with steam is initiated during the start-up phase of SAGA.
Moreover, this invention provides a basis for understanding how the effects of solvent early in a SAGD operation can affect later stages of a SAGA operation, and what operational changes may need to be performed to help optimize the overall SAGO
operation. Solvent-steam injection during the start-up phase of a SAGD
operation can lead to enhanced solvent recovery, lower SORs, and lower production time for hydrocarbon recovery. Moreover, the matching of timing of solvent addition, solvent composition and solvent concentration with the stage of SAGD operation can help improve the overall SAGD operation.
As an example of how early solvent addition can influence the operational choices for any given SAGA operation, according to the present invention, heavier or more dense solvents can be added early in a SAGD operation to assist in establishing inter-well communication. Once inter-well communication has been established, the focus of the SAGD operation is shifted to maximize steam chamber growth and in allowing the solvent to have maximum effect on the surrounding bitumen. Thus, at later stages in the SAGD operation, the solvent may be changed to lighter or less dense solvents compared to the solvent chosen during the start-up phase of the SAGD operation, With reference to the Figures and Examples, the invention will be described in more detail below, Figure 1 shows a conventional SAGD or SCIS operation. The injection of steam 10 into a first horizontal well 20 (also referred to as the injection well) may result in the mobilization of hydrocarbons 30 inside a formation 40, which is generally a formation consisting of viscous hydrocarbons of limited mobility such as bitumen. Once thermal energy is applied, the mobilized hydrocarbons may drain to a second horizontal well 50 (also referred to as the production well), and be removed to the surface 60 as a mixed stream 70. The mixed stream 70 may be comprised of hydrocarbons, steam condensate and other materials, such as water, gases, and the like, When the steam 10 is mixed with solvent during injection, the mixed stream 70 also includes recovered solvent, The mixed stream 70 from one or more production wells may be combined and sent to a processing facility 80. At the processing facility 80, various processing operations can occur but generally, the water and hydrocarbons from mixed stream 70 can be separated, and the hydrocarbons 86 sent on for further refining. Water from the separation may be recycled to a steam generation unit within the facility 80, with or without further treatment, and used to generate the steam 10 used for the SAGE) operation or SCIS
process. Moreover, solvent may be recovered in the facility 80 and re-used for the SAGD
operation or SCIS process. It is useful to use solvent which is produced on-site so as to reduce blending requirements.
According to the present method, solvent is added during the start-up phase of a SAGD
operation. The solvent is injected as a vapor, along with steam at a time before which there is little or no inter-well communication between the injection and production wells, so that mobilized hydrocarbons fluids cannot be produced. In practice, this means that one may inject the steam-solvent mixture at the very start of the SAG-D
operation, or at least at some point before the SAGD operation is transitioned to ramp-up phase, The injection of solvent with steam is expected to reduce the partial pressure of steam slightly, causing a marginal depression in temperature. Upon condensation, steam forms a separate liquid phase, and the solvent becomes miscible with bitumen. The condensation of solvent occurs initially by dissolution in the oil phase to achieve local equilibrium.
When the partial pressure of the solvent becomes higher than its vapour pressure due to condensation of water vapour and/or a reduction in temperature, the solvent condenses and becomes miscible with bitumen. Thus, the methods described herein rely on both solvent and thermal benefits to reduce the viscosity of the heavy crude oil or bitumen.
The solvent benefits are provided by dilution of bitumen or heavy crude oil through continuous or intermittent injection of solvents that are condensable under reservoir operating conditions. The combination of heat transfer processes and mass transfer processes (molecular diffusion, mechanical dispersion and convective mixing) accelerates the reduction in hydrocarbon viscosity, improving hydrocarbon recovery.
Once the first steam-solvent mixture is injected, additional steam-solvent mixtures of varying composition or the same composition, may be injected into the formation, either continuous with or intermittent with the first steam-solvent mixture, Gas may also be injected. In other words, the injection of the first steam-solvent mixture during the start-up phase does not limit the solvents that can be used at later stages of the SAGD
operation.
As will be described in the Examples below, solvents such as cracked naphtha and gas condensate can be used as the solvent. Figure 2 shows cumulative produced oil when various concentrations of cracked naphtha are injected with steam using a model experimental set-up. Oil production rates peak earlier, and are consistently higher when cracked naphtha is injected along with steam during the start-up phase of the SAGD
operation. Figure 4 shows oil production rate when various concentrations of gas condensate are added during the start-up phase of a SAGD operation as modelled in an experimental set-up. These results indicate that solvent injection during the start-up phase of a SAGD operation allows for more rapid establishment of oil production rates, and that establishing good communication early allows for overall better performance of a SAGD
operation.
Figure 3 shows oil drainage rate versus time when various concentrations of cracked naphtha are injected into a model experimental set-up. Oil drainage rates are higher at earlier times when solvent is co-injected with steam. Figure 5 shows oil drainage rate versus time when various concentrations of gas condensate are injected into a model experimental set-up.
Some of the benefits of the present invention include:
= Solvent addition during start-up accelerates oil production rates and reduces SOR
compared to SAGD operations carried out without solvent addition to steam.
= Solvent recovery is improved, In some cases, solvent recovery can be as high as 72.1% and 99.5% depending on solvent type, concentration and operating strategy. Steam chamber initiation and growth is faster when solvent is added during the start-up phase of SAGD, allowing for more rapid transition to the subsequent phases of the SAGD operation.
= Starting solvent injection earlier extends the solvent-bitumen contact time and consequently increases the solvent penetration depth into the bitumen.
= Early solvent injection allows more time for the solvent to reduce interfacial tension and residual oil saturation in the area swept by the steam chamber.
Co-injecting multi-component solvents with steam early in a SAGD operation provides additional operational flexibility.
The volume of solvent in the injected steam can be from about 0,1 vol% to about 30 vol%
of the total volume of the steam-solvent mixture. More particularly, the volume of solvent may be between 5 vol% and 30 vol% of the total volume of the steam-solvent mixture.
A variety of solvents can be used in the method and system described herein.
The solvent should be chosen based on miscibility in bitumen, availability, cost and therrno-physical properties. The steam and vaporized solvent are injected together during the start-up phase. During the start-up phase, there is little or no substantial inter-well communication, and the steam chamber is only beginning to be formed. As such, it should be possible to use a heavier or denser solvent initially during the start-up phase and later switch to a lighter or less solvent at a later stage within start-up or after inter-well communication has been established. A heavier solvent would tend to condense to the liquid phase earlier than a lighter or less dense solvent and thus, the heavier solvent can help to mobilize the inter-well region. Also, once a steam chamber has formed (e.g.
after the start-up phase is complete), it would be useful to employ a solvent that remains in the vapor phase at least until such time that the solvent reaches the bitumen-interface of the steam chamber. Generally, when the term "heavy solvent" is used herein the term refers to a solvent with a typical boiling range of 177-343 C and generally includes hydrocarbon liquids in the C10 to C20 range such as kerosene and diesel.
"Light solvent"
means a solvent with a typical boiling range of 36-100 C and generally include hydrocarbon liquids in the C5 to C7 range such as pentane, hexane, cyclonexane and toluene). As someone skilled in art would appreciate, various combinations of light solvents and heavy solvents could be combined, provided that a light solvent has a higher proportion of light hydrocarbons and a heavy solvent has a higher proportion of heavy hydrocarbons.
Although there may be some benefit to using a heavier solvent in the start-up phase, it is not strictly speaking necessary to do so, as the benefits of this method can be seen with lighter solvents and any variety of solvents may be used in the methods described herein, Examples of solvents that may be used include hexane, gasoline, kersosene, naphtha, natural gas condensates, xylerie, diesel, benzene, toluene, distallates, Cl-hydrocarbons (butane, methane, pentane, etc.) and mixtures thereof, cracked naphtha etc.
The solvent may be a single- or multi-component solvent. The use of multi-component solvents is recommended because they provide additional operational flexibility compared to single component solvents, and because from a commercial perspective, they are more readily available and cheaper to obtain compared to single component solvents. Multi-component solvents are better able to account for pressure fluctuations.
For example, a multi-component solvent containing hexane and lighter components such as butane can be more effective over a wider range of pressures relative to a single component. Additionally, solvents should be chosen such that asphaltene precipitation is less likely to take place.
The solvent is generally between 0.1 ¨ 30 vol% of the total steam-solvent mixture volume, The amount of solvent used is based on oil viscosity at initial conditions, operating pressure, the formation permeability and the composition of solvent.
The solvent is injected in the vapor phase and should remain in the vapor phase for a pre-determined time before condensing in the reservoir. Once the steam chamber begins to grow (e.g. when the start-up phase is complete and some inter-well communication has been established), the solvent should remain as a vapor within the steam chamber as the solvent travels towards the bitumen interface. Solvents are chosen that have suitable thermodynamic characteristics, and the amount of solvent is chosen such that the solvent remains in the vapor phase for the appropriate time and condenses at the desired time and place within the reservoir.
It may be appropriate to vary the solvent composition at different times during the SAGD
operation and/or to add additives to account for pressure fluctuations and/or operating variability. Also, the concentration of solvent may be changed throughout the SAGD
operation. Thus, the present invention allows for operational flexibility of a SAGD
process in terms of the timing of solvent addition, and the concentration and type of solvent in accordance with changing reservoir conditions and operational requirements.
In one embodiment, a heavier solvent is injected along with steam into the injection well during start-up, while simultaneously injecting a lighter solvent in a steam-solvent mixture into the production well. The heavier solvent would tend to diffuse towards to the production well, while the lighter solvent would tend to diffuse towards the injection well. The two solvents would act concertedly to sweep the inter-well zone between the injection and production well, thus allowing for inter-well communication to be more established more quickly during the start-up phase.
An example of multi-component solvents that may be used include cracked naphtha and natural gas condensate. "Cracked naphtha" generally refers to naphthas that come from refinery processes such as catalytic or thermal cracking or visbreaking. There are many different cracked naphtha compositions, and a representative sample composition is presented in the Examples. Typically, cracked naphtha is high in olefins.
Similarly, natural gas condensate may have a variety of compositions depending on the source, but generally has a specific gravity ranging from 0.5 to 0.8 and is composed of hydrocarbons such as propane, butane, pentane, hexane, etc. Gas condensate generally has very low viscosity and is frequently used as a diluent to dilute heavier oils to meet pipeline specifications.
Whether a solvent is in the vapour phase depends on temperature and pressure conditions in the reservoir. The pressure and temperature should be suitable such that the solvent has maximum miscibility in bitumen. In practice, this can be achieved by controlling the operating pressure. The optimal pressure that allows for this during the start-up phase is generally the maximum operating pressure of the injection well. The production well will be at reservoir pressure. This will allow for the maximum pressure differential during the start-up phase. The thermodynamic conditions have to be chosen so as allow for maximum solubility of the solvent in bitumen, regardless of the concentration of solvent.
While normally the injection well is kept at maximum operating pressure during start-up, when stearn-solvent is also injected into the production well, it may be possible to switch the operating pressures of the production and injection wells, provided that a pressure differential is maintained between them. This may assist in more rapid mobilization of bitumen in the inter-well region. It is useful to maintain a large pressure differential during start-up so as to promote the conductive movement of solvent and steam into the inter-well zone. Increasing pressure allows for more solvent to be absorbed by the bitumen. When solvent is mixed with the bitumen, the bitumen viscosity is lowered, and the bitumen is drained. Once the bitumen is drained, a new "layer" of cold bitumen is exposed to solvent and steam. Thus, increasing the pressure allows for the steam and solvent to penetrate into the conductively heated region, It is thus important to maintain the pressure to allow the solvent to be exposed to fresh bitumen and avoid the reflux of solvent.
The below examples illustrate some of the inventive features of the invention but are not intended to limit the scope of the invention.
Example 1: sac using Cracked Naphtha A series of high pressure experiments was conducted using a highly instrumented physical model to accurately measure pressure, temperature and fluid flow rates using oil samples from the field and typical SAG]) operating conditions. Upon completion of each experiment, extensive produced fluid and porous media analyses were conducted to evaluate the impact of solvent injection on SAGD performance, The lab results demonstrated that co-injecting solvent with steam increases oil production rates and reduces SOR. The results are more fully described in Al-Murayri, Mohammed Taha (2014) Experimental Investigation of Expanding Solvent Steam Assisted Gravity Drainage Using Multieomponent Solvents. (Ph.D. thesis), University of Calgary (December 2014).
Experiments 3, 4 and 5 were conducted to investigate the impact of co-injecting different amounts of cracked naphtha with steam on SAGO performance. Cracked naphtha is a multi-component solvent that is readily available as a product of the Nexen Long Lake upgrader.
= Experiment 2 refers to an experiment set-up where only steam was injected using the SAGD injection well to establish a SAGD baseline that could be compared with subsequent SCIS experiments.
= Experiment 3 refers to the experiment set-up where 10 vol% cracked naphtha combined with steam was used to enhance SAGD performance.
= Experiment 4 refers to the experiment set-up where 15 vol% cracked naphtha combined with steam is used to enhance SAGD performance.
= Experiment 5 refers to the experiment set-up where 5 vol% cracked naphtha combined with steam is used to enhance SAGD performance.
All of Experiments 2 to 5 were commenced by injecting steam and cracked naphtha into the injector well in the model set-up. The cracked naphtha concentration (per total steam and solvent volume on a cold liquid equivalent basis) in the injected steam-solvent mixture ranges from 5-15% volume. Low injection rates were used initially then steam-solvent injection was increased. The steam-solvent injection pressure was fixed at 2,100 1-cl'a and the steam and solvent injection rates were maintained such that the pressure difference between the injection and production wells remained at a reasonable level throughout the life of the process. The injectant was pre-heated to saturated steam temperatures before passing through the steam generator to be further heated to superheated steam conditions, The cracked naphtha used in Experiments 2 to 5 had the following composition:
Component Composition (Mole _____________________________ Fraction) nC4 0.0063 iC5 0.0565 nCs 0.0816 C6 0.1391 C7+ 0.7165 _______ Total 1.000 The produced fluids from Experiments 2, 3, 4 and 5 were analyzed extensively to evaluate the impact of injecting different amounts of cracked naphtha on SAGD
performance.
As shown in Figure 3, co-injecting cracked naphtha at the early stages of the SAGD
process can potentially accelerate the start-up phase even when only 5 vol% of cracked naphtha is used. The SAGD wells are normally switched from a circulation mode of operation to a SAGD mode of operation when the viscosity in the inter-well region is between 600-1200 cp, and this can be achieved sooner by co-injecting cracked naphtha with steam due to the synergy of heat and mass transfer processes. The experiments also showed that the injection of cracked naphtha with steam allows more oil to be drained using lower amounts of steam. The best performance was achieved using 10 vol%
of cracked naphtha.
Figure 3 also shows that the impact of solvent addition is more pronounced in the beginning of the drainage process. In fact, the slopes of the cumulative produced oil versus cinnulative injected steam were nearly the same after 4000 ml of steam injection.
Therefore, solvent injection is most effective when initiated early in the process. Figure 2 shows. cumulative oil produced versus cumulative injected steam. The results also suggested that co-injecting cracked naphtha can extend the economic window of a SAGD
operation, by allowing oil drainage to continue at lower steam oil ratios, particularly in the presence steam thief zones such as top water underneath the reservoir overburden.
The energy efficiency of the baseline SAGD and cracked naphtha SCIS cases deteriorated with time.
The experiments showed that cumulative steam oil ratios (cSOR) when cracked naphtha was used were lower compared to experiments where no cracked naphtha was added to the steam. Even with only 5 vol% of cracked naphtha, SCIS had a lower cSOR
than SAGD without cracked naphtha addition.
Example 2: SCIS using Gas Condensate The same experimental set-up as used for the cracked naphtha experiments was used to test the effects of gas condensate added with steam on SAGD operation. Gas condensate is a multicomponent solvent that is often use to blend produced bitumen to make it suitable for pipeline transportation.
= Experiment 6 refers to the experiment set-up where 5 vol% gas condensate combined with steam was used to enhance SAGD performance, = Experiment 7 refers to the experiment set-up where 10 vol% gas condensate combined with steam was used to enhance SAGE) performance, = Experiment 8 refers to the experiment set-up where 15 vol% gas condensate combined with steam was used to enhance SAGD performance.
Water and gas condensate were mixed before passing through the pre-heater and steam generator toward the heel of the SAGD injection well. The steam and gas condensate mixture were co-injected into the reservoir using the SAGD injection well.
Steam and solvent injection was increased gradually.
Gas condensate concentration in the steam-solvent injection ranged from 5-15 vol% of the liquid stream The produced fluids from Experiments 6, 7 and S were analyzed extensively to evaluate the impact of injecting different amounts of gas condensate on SAGD performance.
The injection of gas condensate with steam accelerates the redaction of bitumen viscosity and facilitates inter-well communication between the SAGD wells. Figure 5 shows that that co-injecting gas condensate with steam accelerated the start-up phase of the SAGD
process even when only 5 vol% of gas condensate was used. The experiments showed that using the same amount of steam, Experiment 8 (15 % volume gas condensate) produced more oil relative to baseline SAGD and Experiments 6 (5% volume gas condensate) and 7 (10% volume gas condensate). As with the experiments using cracked naphtha, the results show that co-injecting gas condensate can extend the economic window for SAGD, by allowing oil drainage to continue at lower steam oil ratios, The energy efficiency of SAGD and gas condensate SCIS cases deteriorated with time, Cumulative steam oil ratios (cSOR) for all experiments in which gas condensate was added were lower than SAGD operations having no gas condensate addition. cSOR
decreased progressively as the amount of co-injected gas condensate increased.
The lowest cSOR was achieved in where 15 vol% of gas condensate was used.
The results of this study show that the injection of cracked naphtha and gas condensate with steam can enhance SAGD performance, Using the same amount of steam, SAGD
with cracked naphtha or gas condensate can increase oil recovery and reduce cumulative steam oil ratio significantly relative to SAGD. This can reduce greenhouse gas emissions while making SAGD more energy-efficient and cost-effective.
"Start-up" phase of a SAGD operation refers to the start or initiation of a SAGD
operation. During the start-up phase, substantial inter-well communication has been not been established. Thus, the hydrocarbons in the reservoir are not yet mobile.
Also, during the start-up phase, steam chamber growth is initiated, but there is little or no substantial steam chamber formed per se. In the prior art literature, the "start-up" phase of a SAGD
operation may also be referred to as the circulation phase. For purposes of this disclosure, the terms "start-up phase" and "circulation phase" are intended to have the same meaning and this disclosure is intended to any process for which solvent is added early in the SAGD operation, before inter-well communication has been established and at least before the time that production of hydrocarbons has occurred.
As used throughout this disclosure, the volume of solvent or "vol%" solvent refers to the volume of solvent per total steam plus solvent volume on a cold liquid equivalent basis.
"Solvent co-injection with steam" (SCIS) refers to a variation of SAGD wherein solvent is co-injected with steam to mobilize bitumen through simultaneous heat and mass transfer processes, As used throughout this disclosure, SCIS means a SAGD
operation in which solvent is added along with steam.
"Viscous hydrocarbon-containing formation" means a subterranean formation containing oils of high viscosity and which are largely incapable of being recovered without the use of heat or dilution. An example of a viscous hydrocarbon-containing formation is an oil sands reservoir with bitumen.
Many commercial SAGD processes involve various stages of operations. These stages are sometimes classified as start-up, ramp-up, conventional or normal SAGD and blow-down operations. Each of these phases is described briefly below.
Conventionally, the start-up phase of a SAGD operation is performed to establish thermal and hydraulic communication between SAGD injection and production wells.
Initially, the reservoir contains cold bitumen of high viscosity and limited mobility so that there is no fluid communication between the injection and production wells. The start-up phase may include circulating steam through one or both the injection and production wells, thereby establishing inter-well communication. The time required to establish fluid communication is reservoir and well-pair dependent, but relates to factors such as injector-to-producer well separation along the horizontal well length, injected steam temperatures and reservoir pressures at which circulation is maintained.
Typical steam circulation time is around 120 days, but may be shorter or longer. Once inter-well conununication is established, well pairs can be transitioned to the ramp-up phase of the SAGD operation.
The ramp-up phase of a SAGD operation generally refers to a period of time after conununication has been established between the SAGD injection and production wells.
The steam chamber has already been established, and grows vertically up to the top of the bitumen zone, Mobilized oil and water are removed from the production well.
The entire length of the well pair eventually becomes heated and oil production rates peak.
Conventional or normal SAGD operation refers to the phase after the ramp-up phase.
During this phase, the steam chamber has essentially reached almost maximum vertical height and continues to extend laterally. The oil production rates are steady or possibly start to decline.
Blow-down operations refers to a phase wherein steam injection is terminated and often, a non-condensable gas in injected into the steam chamber to maintain pressure, Oil production rates decline over time and eventually the operation becomes uneconomic.
Thereafter, the SAGD well pairs may be abandoned, The present invention relates to methods and systems for enhancing the recovery of hydrocarbons such as heavy oil through solvent injection during the initial or so-called start-up phase of SAGD and SAGD-related operations, Using the same amount of steam, solvent injection with steam during the start-up phase of a SAGD operation (e.g. before substantial inter-well fluid communication has been established between the injection well and the production well) increases oil recovery and reduces cumulative steam-to-oil ratio (SOR) relative to a SAGD operation in which there has been no solvent addition during the start-up phase of SAGD.
The addition of solvent early in a SAGD operation (e.g. during the start-up phase of SAGD and/or at least before substantial inter-well communication has been established) accelerates the mobilization of bitumen in the inter-well region, and promotes the rapid formation of a steam chamber. The ability to establish good inter-well communication during the start-up phase shortens the time to transition to the ramp-up phase and allows for a more efficient SAGD operation (e.g. earlier peak oil production, decreased SOR, etc.). Once good communication is established, there is continued development and growth of the steam chamber, and the entirety of the SAGD operation is enhanced.
Establishing good communication early on in a SAGD operation allows for better ramp-up and better overall SAGD performance. The time required to switch between the start-up phase of a SAGD operation to the ramp-up phase of a SAGD-mode of operation is diminished when solvent is added during the start-up phase of a SAGD
operation. The more rapid and/or enhanced mobilization of bitumen is due to the combined effects of conduction and dilution by solvent on viscosity of the bitumen in the inter-well zone, and all of these effects are particularly pronounced when solvent is injected as early as possible in the SAGD operation.
Further, the use of solvent with steam during the start-up phase of SAGD
allows for more uniform fluid development along the length of the wells, This OCCUrs because of greater dilution of bitumen by solvent along the well segments heated to lower temperatures.
Thus, the timing of solvent injection is important in determining how to optimize the overall efficacy of a SAGD operation. In many prior art studies, the timing of solvent injection is not injected during the start-up phase of the SAGD operation and/or the solvent is only injected sometime after at least some inter-well communication has been established. Also, in many prior art studies, solvent is added late as after peak oil production rates have been observed. This invention differs from these prior studies in that solvent co-injection with steam is initiated during the start-up phase of SAGA.
Moreover, this invention provides a basis for understanding how the effects of solvent early in a SAGD operation can affect later stages of a SAGA operation, and what operational changes may need to be performed to help optimize the overall SAGO
operation. Solvent-steam injection during the start-up phase of a SAGD
operation can lead to enhanced solvent recovery, lower SORs, and lower production time for hydrocarbon recovery. Moreover, the matching of timing of solvent addition, solvent composition and solvent concentration with the stage of SAGD operation can help improve the overall SAGD operation.
As an example of how early solvent addition can influence the operational choices for any given SAGA operation, according to the present invention, heavier or more dense solvents can be added early in a SAGD operation to assist in establishing inter-well communication. Once inter-well communication has been established, the focus of the SAGD operation is shifted to maximize steam chamber growth and in allowing the solvent to have maximum effect on the surrounding bitumen. Thus, at later stages in the SAGD operation, the solvent may be changed to lighter or less dense solvents compared to the solvent chosen during the start-up phase of the SAGD operation, With reference to the Figures and Examples, the invention will be described in more detail below, Figure 1 shows a conventional SAGD or SCIS operation. The injection of steam 10 into a first horizontal well 20 (also referred to as the injection well) may result in the mobilization of hydrocarbons 30 inside a formation 40, which is generally a formation consisting of viscous hydrocarbons of limited mobility such as bitumen. Once thermal energy is applied, the mobilized hydrocarbons may drain to a second horizontal well 50 (also referred to as the production well), and be removed to the surface 60 as a mixed stream 70. The mixed stream 70 may be comprised of hydrocarbons, steam condensate and other materials, such as water, gases, and the like, When the steam 10 is mixed with solvent during injection, the mixed stream 70 also includes recovered solvent, The mixed stream 70 from one or more production wells may be combined and sent to a processing facility 80. At the processing facility 80, various processing operations can occur but generally, the water and hydrocarbons from mixed stream 70 can be separated, and the hydrocarbons 86 sent on for further refining. Water from the separation may be recycled to a steam generation unit within the facility 80, with or without further treatment, and used to generate the steam 10 used for the SAGE) operation or SCIS
process. Moreover, solvent may be recovered in the facility 80 and re-used for the SAGD
operation or SCIS process. It is useful to use solvent which is produced on-site so as to reduce blending requirements.
According to the present method, solvent is added during the start-up phase of a SAGD
operation. The solvent is injected as a vapor, along with steam at a time before which there is little or no inter-well communication between the injection and production wells, so that mobilized hydrocarbons fluids cannot be produced. In practice, this means that one may inject the steam-solvent mixture at the very start of the SAG-D
operation, or at least at some point before the SAGD operation is transitioned to ramp-up phase, The injection of solvent with steam is expected to reduce the partial pressure of steam slightly, causing a marginal depression in temperature. Upon condensation, steam forms a separate liquid phase, and the solvent becomes miscible with bitumen. The condensation of solvent occurs initially by dissolution in the oil phase to achieve local equilibrium.
When the partial pressure of the solvent becomes higher than its vapour pressure due to condensation of water vapour and/or a reduction in temperature, the solvent condenses and becomes miscible with bitumen. Thus, the methods described herein rely on both solvent and thermal benefits to reduce the viscosity of the heavy crude oil or bitumen.
The solvent benefits are provided by dilution of bitumen or heavy crude oil through continuous or intermittent injection of solvents that are condensable under reservoir operating conditions. The combination of heat transfer processes and mass transfer processes (molecular diffusion, mechanical dispersion and convective mixing) accelerates the reduction in hydrocarbon viscosity, improving hydrocarbon recovery.
Once the first steam-solvent mixture is injected, additional steam-solvent mixtures of varying composition or the same composition, may be injected into the formation, either continuous with or intermittent with the first steam-solvent mixture, Gas may also be injected. In other words, the injection of the first steam-solvent mixture during the start-up phase does not limit the solvents that can be used at later stages of the SAGD
operation.
As will be described in the Examples below, solvents such as cracked naphtha and gas condensate can be used as the solvent. Figure 2 shows cumulative produced oil when various concentrations of cracked naphtha are injected with steam using a model experimental set-up. Oil production rates peak earlier, and are consistently higher when cracked naphtha is injected along with steam during the start-up phase of the SAGD
operation. Figure 4 shows oil production rate when various concentrations of gas condensate are added during the start-up phase of a SAGD operation as modelled in an experimental set-up. These results indicate that solvent injection during the start-up phase of a SAGD operation allows for more rapid establishment of oil production rates, and that establishing good communication early allows for overall better performance of a SAGD
operation.
Figure 3 shows oil drainage rate versus time when various concentrations of cracked naphtha are injected into a model experimental set-up. Oil drainage rates are higher at earlier times when solvent is co-injected with steam. Figure 5 shows oil drainage rate versus time when various concentrations of gas condensate are injected into a model experimental set-up.
Some of the benefits of the present invention include:
= Solvent addition during start-up accelerates oil production rates and reduces SOR
compared to SAGD operations carried out without solvent addition to steam.
= Solvent recovery is improved, In some cases, solvent recovery can be as high as 72.1% and 99.5% depending on solvent type, concentration and operating strategy. Steam chamber initiation and growth is faster when solvent is added during the start-up phase of SAGD, allowing for more rapid transition to the subsequent phases of the SAGD operation.
= Starting solvent injection earlier extends the solvent-bitumen contact time and consequently increases the solvent penetration depth into the bitumen.
= Early solvent injection allows more time for the solvent to reduce interfacial tension and residual oil saturation in the area swept by the steam chamber.
Co-injecting multi-component solvents with steam early in a SAGD operation provides additional operational flexibility.
The volume of solvent in the injected steam can be from about 0,1 vol% to about 30 vol%
of the total volume of the steam-solvent mixture. More particularly, the volume of solvent may be between 5 vol% and 30 vol% of the total volume of the steam-solvent mixture.
A variety of solvents can be used in the method and system described herein.
The solvent should be chosen based on miscibility in bitumen, availability, cost and therrno-physical properties. The steam and vaporized solvent are injected together during the start-up phase. During the start-up phase, there is little or no substantial inter-well communication, and the steam chamber is only beginning to be formed. As such, it should be possible to use a heavier or denser solvent initially during the start-up phase and later switch to a lighter or less solvent at a later stage within start-up or after inter-well communication has been established. A heavier solvent would tend to condense to the liquid phase earlier than a lighter or less dense solvent and thus, the heavier solvent can help to mobilize the inter-well region. Also, once a steam chamber has formed (e.g.
after the start-up phase is complete), it would be useful to employ a solvent that remains in the vapor phase at least until such time that the solvent reaches the bitumen-interface of the steam chamber. Generally, when the term "heavy solvent" is used herein the term refers to a solvent with a typical boiling range of 177-343 C and generally includes hydrocarbon liquids in the C10 to C20 range such as kerosene and diesel.
"Light solvent"
means a solvent with a typical boiling range of 36-100 C and generally include hydrocarbon liquids in the C5 to C7 range such as pentane, hexane, cyclonexane and toluene). As someone skilled in art would appreciate, various combinations of light solvents and heavy solvents could be combined, provided that a light solvent has a higher proportion of light hydrocarbons and a heavy solvent has a higher proportion of heavy hydrocarbons.
Although there may be some benefit to using a heavier solvent in the start-up phase, it is not strictly speaking necessary to do so, as the benefits of this method can be seen with lighter solvents and any variety of solvents may be used in the methods described herein, Examples of solvents that may be used include hexane, gasoline, kersosene, naphtha, natural gas condensates, xylerie, diesel, benzene, toluene, distallates, Cl-hydrocarbons (butane, methane, pentane, etc.) and mixtures thereof, cracked naphtha etc.
The solvent may be a single- or multi-component solvent. The use of multi-component solvents is recommended because they provide additional operational flexibility compared to single component solvents, and because from a commercial perspective, they are more readily available and cheaper to obtain compared to single component solvents. Multi-component solvents are better able to account for pressure fluctuations.
For example, a multi-component solvent containing hexane and lighter components such as butane can be more effective over a wider range of pressures relative to a single component. Additionally, solvents should be chosen such that asphaltene precipitation is less likely to take place.
The solvent is generally between 0.1 ¨ 30 vol% of the total steam-solvent mixture volume, The amount of solvent used is based on oil viscosity at initial conditions, operating pressure, the formation permeability and the composition of solvent.
The solvent is injected in the vapor phase and should remain in the vapor phase for a pre-determined time before condensing in the reservoir. Once the steam chamber begins to grow (e.g. when the start-up phase is complete and some inter-well communication has been established), the solvent should remain as a vapor within the steam chamber as the solvent travels towards the bitumen interface. Solvents are chosen that have suitable thermodynamic characteristics, and the amount of solvent is chosen such that the solvent remains in the vapor phase for the appropriate time and condenses at the desired time and place within the reservoir.
It may be appropriate to vary the solvent composition at different times during the SAGD
operation and/or to add additives to account for pressure fluctuations and/or operating variability. Also, the concentration of solvent may be changed throughout the SAGD
operation. Thus, the present invention allows for operational flexibility of a SAGD
process in terms of the timing of solvent addition, and the concentration and type of solvent in accordance with changing reservoir conditions and operational requirements.
In one embodiment, a heavier solvent is injected along with steam into the injection well during start-up, while simultaneously injecting a lighter solvent in a steam-solvent mixture into the production well. The heavier solvent would tend to diffuse towards to the production well, while the lighter solvent would tend to diffuse towards the injection well. The two solvents would act concertedly to sweep the inter-well zone between the injection and production well, thus allowing for inter-well communication to be more established more quickly during the start-up phase.
An example of multi-component solvents that may be used include cracked naphtha and natural gas condensate. "Cracked naphtha" generally refers to naphthas that come from refinery processes such as catalytic or thermal cracking or visbreaking. There are many different cracked naphtha compositions, and a representative sample composition is presented in the Examples. Typically, cracked naphtha is high in olefins.
Similarly, natural gas condensate may have a variety of compositions depending on the source, but generally has a specific gravity ranging from 0.5 to 0.8 and is composed of hydrocarbons such as propane, butane, pentane, hexane, etc. Gas condensate generally has very low viscosity and is frequently used as a diluent to dilute heavier oils to meet pipeline specifications.
Whether a solvent is in the vapour phase depends on temperature and pressure conditions in the reservoir. The pressure and temperature should be suitable such that the solvent has maximum miscibility in bitumen. In practice, this can be achieved by controlling the operating pressure. The optimal pressure that allows for this during the start-up phase is generally the maximum operating pressure of the injection well. The production well will be at reservoir pressure. This will allow for the maximum pressure differential during the start-up phase. The thermodynamic conditions have to be chosen so as allow for maximum solubility of the solvent in bitumen, regardless of the concentration of solvent.
While normally the injection well is kept at maximum operating pressure during start-up, when stearn-solvent is also injected into the production well, it may be possible to switch the operating pressures of the production and injection wells, provided that a pressure differential is maintained between them. This may assist in more rapid mobilization of bitumen in the inter-well region. It is useful to maintain a large pressure differential during start-up so as to promote the conductive movement of solvent and steam into the inter-well zone. Increasing pressure allows for more solvent to be absorbed by the bitumen. When solvent is mixed with the bitumen, the bitumen viscosity is lowered, and the bitumen is drained. Once the bitumen is drained, a new "layer" of cold bitumen is exposed to solvent and steam. Thus, increasing the pressure allows for the steam and solvent to penetrate into the conductively heated region, It is thus important to maintain the pressure to allow the solvent to be exposed to fresh bitumen and avoid the reflux of solvent.
The below examples illustrate some of the inventive features of the invention but are not intended to limit the scope of the invention.
Example 1: sac using Cracked Naphtha A series of high pressure experiments was conducted using a highly instrumented physical model to accurately measure pressure, temperature and fluid flow rates using oil samples from the field and typical SAG]) operating conditions. Upon completion of each experiment, extensive produced fluid and porous media analyses were conducted to evaluate the impact of solvent injection on SAGD performance, The lab results demonstrated that co-injecting solvent with steam increases oil production rates and reduces SOR. The results are more fully described in Al-Murayri, Mohammed Taha (2014) Experimental Investigation of Expanding Solvent Steam Assisted Gravity Drainage Using Multieomponent Solvents. (Ph.D. thesis), University of Calgary (December 2014).
Experiments 3, 4 and 5 were conducted to investigate the impact of co-injecting different amounts of cracked naphtha with steam on SAGO performance. Cracked naphtha is a multi-component solvent that is readily available as a product of the Nexen Long Lake upgrader.
= Experiment 2 refers to an experiment set-up where only steam was injected using the SAGD injection well to establish a SAGD baseline that could be compared with subsequent SCIS experiments.
= Experiment 3 refers to the experiment set-up where 10 vol% cracked naphtha combined with steam was used to enhance SAGD performance.
= Experiment 4 refers to the experiment set-up where 15 vol% cracked naphtha combined with steam is used to enhance SAGD performance.
= Experiment 5 refers to the experiment set-up where 5 vol% cracked naphtha combined with steam is used to enhance SAGD performance.
All of Experiments 2 to 5 were commenced by injecting steam and cracked naphtha into the injector well in the model set-up. The cracked naphtha concentration (per total steam and solvent volume on a cold liquid equivalent basis) in the injected steam-solvent mixture ranges from 5-15% volume. Low injection rates were used initially then steam-solvent injection was increased. The steam-solvent injection pressure was fixed at 2,100 1-cl'a and the steam and solvent injection rates were maintained such that the pressure difference between the injection and production wells remained at a reasonable level throughout the life of the process. The injectant was pre-heated to saturated steam temperatures before passing through the steam generator to be further heated to superheated steam conditions, The cracked naphtha used in Experiments 2 to 5 had the following composition:
Component Composition (Mole _____________________________ Fraction) nC4 0.0063 iC5 0.0565 nCs 0.0816 C6 0.1391 C7+ 0.7165 _______ Total 1.000 The produced fluids from Experiments 2, 3, 4 and 5 were analyzed extensively to evaluate the impact of injecting different amounts of cracked naphtha on SAGD
performance.
As shown in Figure 3, co-injecting cracked naphtha at the early stages of the SAGD
process can potentially accelerate the start-up phase even when only 5 vol% of cracked naphtha is used. The SAGD wells are normally switched from a circulation mode of operation to a SAGD mode of operation when the viscosity in the inter-well region is between 600-1200 cp, and this can be achieved sooner by co-injecting cracked naphtha with steam due to the synergy of heat and mass transfer processes. The experiments also showed that the injection of cracked naphtha with steam allows more oil to be drained using lower amounts of steam. The best performance was achieved using 10 vol%
of cracked naphtha.
Figure 3 also shows that the impact of solvent addition is more pronounced in the beginning of the drainage process. In fact, the slopes of the cumulative produced oil versus cinnulative injected steam were nearly the same after 4000 ml of steam injection.
Therefore, solvent injection is most effective when initiated early in the process. Figure 2 shows. cumulative oil produced versus cumulative injected steam. The results also suggested that co-injecting cracked naphtha can extend the economic window of a SAGD
operation, by allowing oil drainage to continue at lower steam oil ratios, particularly in the presence steam thief zones such as top water underneath the reservoir overburden.
The energy efficiency of the baseline SAGD and cracked naphtha SCIS cases deteriorated with time.
The experiments showed that cumulative steam oil ratios (cSOR) when cracked naphtha was used were lower compared to experiments where no cracked naphtha was added to the steam. Even with only 5 vol% of cracked naphtha, SCIS had a lower cSOR
than SAGD without cracked naphtha addition.
Example 2: SCIS using Gas Condensate The same experimental set-up as used for the cracked naphtha experiments was used to test the effects of gas condensate added with steam on SAGD operation. Gas condensate is a multicomponent solvent that is often use to blend produced bitumen to make it suitable for pipeline transportation.
= Experiment 6 refers to the experiment set-up where 5 vol% gas condensate combined with steam was used to enhance SAGD performance, = Experiment 7 refers to the experiment set-up where 10 vol% gas condensate combined with steam was used to enhance SAGE) performance, = Experiment 8 refers to the experiment set-up where 15 vol% gas condensate combined with steam was used to enhance SAGD performance.
Water and gas condensate were mixed before passing through the pre-heater and steam generator toward the heel of the SAGD injection well. The steam and gas condensate mixture were co-injected into the reservoir using the SAGD injection well.
Steam and solvent injection was increased gradually.
Gas condensate concentration in the steam-solvent injection ranged from 5-15 vol% of the liquid stream The produced fluids from Experiments 6, 7 and S were analyzed extensively to evaluate the impact of injecting different amounts of gas condensate on SAGD performance.
The injection of gas condensate with steam accelerates the redaction of bitumen viscosity and facilitates inter-well communication between the SAGD wells. Figure 5 shows that that co-injecting gas condensate with steam accelerated the start-up phase of the SAGD
process even when only 5 vol% of gas condensate was used. The experiments showed that using the same amount of steam, Experiment 8 (15 % volume gas condensate) produced more oil relative to baseline SAGD and Experiments 6 (5% volume gas condensate) and 7 (10% volume gas condensate). As with the experiments using cracked naphtha, the results show that co-injecting gas condensate can extend the economic window for SAGD, by allowing oil drainage to continue at lower steam oil ratios, The energy efficiency of SAGD and gas condensate SCIS cases deteriorated with time, Cumulative steam oil ratios (cSOR) for all experiments in which gas condensate was added were lower than SAGD operations having no gas condensate addition. cSOR
decreased progressively as the amount of co-injected gas condensate increased.
The lowest cSOR was achieved in where 15 vol% of gas condensate was used.
The results of this study show that the injection of cracked naphtha and gas condensate with steam can enhance SAGD performance, Using the same amount of steam, SAGD
with cracked naphtha or gas condensate can increase oil recovery and reduce cumulative steam oil ratio significantly relative to SAGD. This can reduce greenhouse gas emissions while making SAGD more energy-efficient and cost-effective.
Claims (21)
1. A method for enhancing recovery of hydrocarbons from a viscous hydrocarbon-containing formation intersected by an injection well and a production well, the method comprising:
a) injecting a first steam-solvent mixture into an injection well, wherein the first steam-solvent mixture is introduced before substantial fluid communication has been established within the formation;
b) continuing the injection of the first steam-solvent mixture until such time that fluid communication is established between the injection well and the production well; and c) recovering mobilized hydrocarbons from the production well.
a) injecting a first steam-solvent mixture into an injection well, wherein the first steam-solvent mixture is introduced before substantial fluid communication has been established within the formation;
b) continuing the injection of the first steam-solvent mixture until such time that fluid communication is established between the injection well and the production well; and c) recovering mobilized hydrocarbons from the production well.
2. The method of claim 1, further comprising injecting the first steam-solvent mixture into the production well.
3. The method of claim 1, further comprising injecting steam into the injection well, the production well or into both the injection well and the production well, prior to injecting the first steam-solvent mixture in the injection well.
4. The method of claim 1, further comprising discontinuing injection of the first steam-solvent mixture, and injecting steam alone into either the production well or the injection well prior to recovering mobilized hydrocarbons from the production well.
5. The method of claim 1, further comprising discontinuing injection of the first steam-solvent mixture and injecting a second steam-steam mixture into the injection well prior to the recovering of the mobilized hydrocarbons.
6. The method of claim 1, further comprising discontinuing injection of the first steam-solvent mixture and injecting a second steam-steam mixture into the injection well once inter-well communication has been established between the production well and the injection well.
7. The method of claim 5 or 6, wherein the solvent in the second steam-solvent mixture has either a) a lower density or b) a higher proportion of lighter hydrocarbons compared to the solvent in the first steam-solvent mixture.
8. The method of claim 6, wherein the solvent in the second steam-solvent mixture is at least 10%, 20%, 30% or 40% less dense than the solvent in the first steam-solvent mixture.
9. The method of claim 1, wherein the solvent in the first steam-solvent mixture is naphtha; toluene, benzene, xylene or other aromatic solvent, an aliphatic hydrocarbon having between 4 carbons and 30 carbons per molecule, a gas condensate or any combination thereof.
10. The method of claim 1, wherein the solvent in the first steam-solvent mixture is cracked naphtha or a gas condensate,
11. The method of claim 1, further comprising operating the injection well at maximum operating pressure while operating the production well at reservoir pressure.
12. The method of claim 12, further comprising switching the pressures at which the injection and production wells are operated at such that the injection well is operated at reservoir pressure, while the production well is operated at maximum operating pressure such that the pressure differential between the wells is maintained.
13. The method of claim 1, wherein the solvent is selected to avoid asphaltene deposition.
14. The method of claim 1, comprising injecting the first solvent-steam mixture in a greater amount, or for a greater duration based on the temperature of the reservoir ang/or distance between the injection well and the production well,
15. The method of claim 1, further comprising providing an infill well between the injection well and the production well, and continuing injecting the first steam-solvent mixture until such time that mobilized hydrocarbons can be recovered from the infill well.
16. A method of recovering bitumen from an oil sands reservoir comprising:
(a) injecting a first steam-solvent mixture into a first horizontal well to establish fluid communication with the reservoir;
(b) injecting a second steam-solvent mixture into a first horizontal well or a second horizontal well, wherein the second horizontal well is below the first horizontal well, wherein the solvent in the first solvent-steam mixture has a higher density compared to the solvent in the second steam-solvent mixture;
and (c) recovering mobilized bitumen from the second horizontal well.
(a) injecting a first steam-solvent mixture into a first horizontal well to establish fluid communication with the reservoir;
(b) injecting a second steam-solvent mixture into a first horizontal well or a second horizontal well, wherein the second horizontal well is below the first horizontal well, wherein the solvent in the first solvent-steam mixture has a higher density compared to the solvent in the second steam-solvent mixture;
and (c) recovering mobilized bitumen from the second horizontal well.
17. The method of claim 17, father comprising injecting steam prior to the injecting the first steam-solvent mixture and/or prior to injecting the second steam-solvent mixture.
18. The method of claim 16, wherein the solvent in the first steam-solvent mixture is a heavy hydrocarbon and the solvent in the second steam-solvent mixture is a light hydrocarbon.
19. The method of claim 17, wherein the solvent in the first steam-solvent mixture has a higher proportion of heavy hydrocarbons compared to the solvent in the second steam-solvent mixture.
20. A method of establishing fluid communication between an injection well and a production well, comprising:
while stream is being supplied to an inter-well region disposed between the injection well and the production well, supplying hydrocarbon solvent material to the inter-well region, such that the viscosity of the hydrocarbon disposed within the inter-well region is decreased through the combined effects of the steam and the solvent.
while stream is being supplied to an inter-well region disposed between the injection well and the production well, supplying hydrocarbon solvent material to the inter-well region, such that the viscosity of the hydrocarbon disposed within the inter-well region is decreased through the combined effects of the steam and the solvent.
21. A method of establishing fluid communication between an injection well and a production well, comprising:
supplying, simultaneously, to an inter-well region disposed between the injection well and the production well, steam and a hydrocarbon solvent material.
supplying, simultaneously, to an inter-well region disposed between the injection well and the production well, steam and a hydrocarbon solvent material.
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| PCT/CA2014/000546 WO2015000065A1 (en) | 2013-07-05 | 2014-07-07 | Accelerated solvent-aided sagd start-up |
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| US10487636B2 (en) | 2017-07-27 | 2019-11-26 | Exxonmobil Upstream Research Company | Enhanced methods for recovering viscous hydrocarbons from a subterranean formation as a follow-up to thermal recovery processes |
| US11002123B2 (en) | 2017-08-31 | 2021-05-11 | Exxonmobil Upstream Research Company | Thermal recovery methods for recovering viscous hydrocarbons from a subterranean formation |
| US11142681B2 (en) | 2017-06-29 | 2021-10-12 | Exxonmobil Upstream Research Company | Chasing solvent for enhanced recovery processes |
| US11261725B2 (en) | 2017-10-24 | 2022-03-01 | Exxonmobil Upstream Research Company | Systems and methods for estimating and controlling liquid level using periodic shut-ins |
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| CN104747156A (en) * | 2015-03-23 | 2015-07-01 | 中国石油天然气股份有限公司 | Exploitation method and injection system for oil reservoir of super heavy oil |
| US11428086B2 (en) | 2015-04-27 | 2022-08-30 | Conocophillips Company | SW-SAGD with between heel and toe injection |
| CN106368659B (en) * | 2015-07-20 | 2019-06-11 | 中国石油天然气股份有限公司 | Vapor equalization method and vapour driving oil recovery oil system during raising steam drive oil production |
| CA2900711A1 (en) | 2015-08-18 | 2017-02-18 | Statoil Canada Limited | Pressure swing solvent assisted well stimulation |
| WO2017053865A1 (en) | 2015-09-23 | 2017-03-30 | Conocophillips Company | Global monitoring system for critical equipment performance evaluation |
| CA3005960C (en) | 2015-11-22 | 2024-04-09 | XDI Holdings, LLC | Method, apparatus, and system for enhanced oil and gas recovery with super focused heat |
| US10995596B2 (en) | 2015-12-01 | 2021-05-04 | Conocophillips Company | Single well cross steam and gravity drainage (SW-XSAGD) |
| CA3011861C (en) | 2017-07-19 | 2020-07-21 | Conocophillips Company | Accelerated interval communication using open-holes |
| CN108868719B (en) * | 2018-07-09 | 2020-07-10 | 中国石油天然气股份有限公司 | Method for producing crude oil in SAGD wedge-shaped area |
| CN109403935B (en) * | 2018-09-30 | 2020-10-09 | 中海石油(中国)有限公司 | Oil yield calculation method for oil sand SAGD encrypted well |
| CN110005399B (en) * | 2019-04-16 | 2022-05-31 | 重庆科技学院 | Experimental method for measuring volume of retrograde condensate oil containing excessive water condensate gas |
| US11821294B2 (en) * | 2020-06-18 | 2023-11-21 | Cenovus Energy Inc. | Methods for recovering solvent and producing hydrocarbons from subterranean reservoirs |
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- 2014-07-07 CA CA2917260A patent/CA2917260A1/en not_active Abandoned
- 2014-07-07 CN CN201480048143.8A patent/CN105518250A/en active Pending
- 2014-07-07 WO PCT/CA2014/000546 patent/WO2015000065A1/en active Application Filing
- 2014-07-07 CA CA2917263A patent/CA2917263C/en active Active
- 2014-07-07 WO PCT/CA2014/000547 patent/WO2015000066A1/en active Application Filing
- 2014-07-07 CN CN201480046969.0A patent/CN105473811A/en active Pending
- 2014-12-12 CA CA2952864A patent/CA2952864C/en active Active
Cited By (4)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US11142681B2 (en) | 2017-06-29 | 2021-10-12 | Exxonmobil Upstream Research Company | Chasing solvent for enhanced recovery processes |
| US10487636B2 (en) | 2017-07-27 | 2019-11-26 | Exxonmobil Upstream Research Company | Enhanced methods for recovering viscous hydrocarbons from a subterranean formation as a follow-up to thermal recovery processes |
| US11002123B2 (en) | 2017-08-31 | 2021-05-11 | Exxonmobil Upstream Research Company | Thermal recovery methods for recovering viscous hydrocarbons from a subterranean formation |
| US11261725B2 (en) | 2017-10-24 | 2022-03-01 | Exxonmobil Upstream Research Company | Systems and methods for estimating and controlling liquid level using periodic shut-ins |
Also Published As
| Publication number | Publication date |
|---|---|
| CA2917263A1 (en) | 2015-01-08 |
| CA2917263C (en) | 2021-12-14 |
| WO2015000065A1 (en) | 2015-01-08 |
| CA2952864A1 (en) | 2016-01-14 |
| CA2952864C (en) | 2022-03-08 |
| CN105473811A (en) | 2016-04-06 |
| WO2015000066A1 (en) | 2015-01-08 |
| CN105518250A (en) | 2016-04-20 |
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