US20150034313A1

US20150034313A1 - In situ combustion with a mobile fluid zone

Info

Publication number: US20150034313A1
Application number: US14/327,446
Authority: US
Inventors: Simon Gittins; Xinjie Wu
Original assignee: Cenovus Energy Inc
Current assignee: Cenovus Energy Inc
Priority date: 2013-07-12
Filing date: 2014-07-09
Publication date: 2015-02-05
Also published as: CA2856914C; CA2856914A1

Abstract

A process for hydrocarbon recovery from an oil sands reservoir having a mobile fluid zone above a bitumen zone. The process includes generating, in the bitumen zone a mobilized and through a mobility enhancing process. The process also includes recovering at least some of the original oil-in-place and injecting an oxidizing gas through an oxidizing gas injection well into the reservoir to support in situ combustion in the reservoir. The process includes generating fluid communication between the mobile fluid zone and the mobilized zone and recovering hydrocarbons mobilized by the in situ combustion using a hydrocarbon production well that is in fluid communication with the mobile fluid zone and the mobilized zone.

Description

INCORPORATION BY REFERENCE TO ANY PRIORITY APPLICATIONS

Any and all applications for which a foreign or domestic priority claim is identified in the Application Data Sheet as filed with the present application are hereby incorporated by reference under 37 CFR 1.57. This application claims the benefit of U.S. Provisional Application No. 61/845,720, filed Jul. 12, 2013, entitled IN SITU COMBUSTION WITH A MOBILE FLUID ZONE, the entire contents of which are herein incorporated by reference.

FIELD

The present disclosure relates to methods for recovery of viscous hydrocarbons from oil sands deposits using in situ combustion.

BACKGROUND

A variety of processes are used to recover viscous hydrocarbons, such as heavy oils and bitumen, from oil sands deposits. Extensive deposits of viscous hydrocarbons exist around the world, including large deposits in the Northern Alberta oil sands, that are not susceptible to standard oil well production technologies. One problem associated with producing hydrocarbons from such deposits is that the hydrocarbons are too viscous to flow at commercially relevant rates at the temperatures and pressures present in the reservoir.
In some cases, such deposits are mined using open-pit mining techniques to extract hydrocarbon-bearing material for later processing to extract the hydrocarbons. Alternatively, thermal techniques may be used to heat the oil sands reservoir to mobilize the hydrocarbons and produce the heated, mobilized hydrocarbons from wells.
One thermal method of recovering viscous hydrocarbons using two vertically spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). Various embodiments of the SAGD process are described in Canadian Patent No. 1,304,287 and corresponding U.S. Pat. No. 4,344,485. In the SAGD process, steam is pumped through an upper, horizontal, injection well into a viscous hydrocarbon reservoir while mobilized hydrocarbons are produced from a lower, parallel, horizontal, production well that is vertically spaced and near the injection well. The injection and production wells are located close to the bottom of the hydrocarbon deposit to collect the hydrocarbons that flow toward the bottom.
The SAGD process is believed to work as follows. The injected steam initially mobilizes the hydrocarbons to create a steam chamber in the reservoir around and above the horizontal injection well. The term “steam chamber” is utilized to refer to the volume of the reservoir that is saturated with injected steam and from which mobilized oil has at least partially drained. As the steam chamber expands upwardly and laterally from the injection well, viscous hydrocarbons in the reservoir are heated and mobilized, in particular, at the margins of the steam chamber where the steam condenses and heats the viscous hydrocarbons by thermal conduction. The mobilized hydrocarbons and aqueous condensate drain, under the effects of gravity, toward the bottom of the steam chamber, where the production well is located. The mobilized hydrocarbons are collected and produced from the production well. The rate of steam injection and the rate of hydrocarbon production may be modulated to control the growth of the steam chamber and ensure that the production well remains located at the bottom of the steam chamber in an appropriate position to collect mobilized hydrocarbons.
In Situ Combustion (ISC) may be utilized to recover hydrocarbons from underground oil sands reservoirs. ISC includes the injection of an oxidizing gas into the porous rock of a hydrocarbon-containing reservoir to ignite and support combustion of the hydrocarbons around the wellbore. ISC may be initiated using an artificial igniter such as a downhole heater or by pre-conditioning the formation around the wellbores and promoting spontaneous ignition. The ISC process, also known as fire flooding or fireflood, is sustained and the ISC fire front moves due to the continuous injection of the oxidizing gas. The heat generated by burning the heavy hydrocarbons in place produces hydrocarbon cracking, vaporization of light hydrocarbons and reservoir water in addition to the deposition of heavier hydrocarbons known as coke. As the fire moves, the burning front pushes a mixture of hot combustion gases, steam, and hot water, which in turn reduces oil viscosity and the oil moves toward the production well. Additionally, the light hydrocarbons and the steam move ahead of the burning front, condensing into liquids, facilitating miscible displacement and hot waterflooding, which contribute to the recovery of hydrocarbons.
Canadian Patent 2,096,034 to Kisman et al. and U.S. Pat. No. 5,211,230 to Ostapovich et al. disclose a method of in situ combustion for the recovery of hydrocarbons from underground reservoirs, sometimes referred to as Combustion Split production Horizontal well Process (COSH) or Combustion Overhead Gravity Drainage (COGD). The disclosed processes include gravity drainage to a basal horizontal well in a combustion process. A horizontal production well is located in the lower portion of the reservoir. A vertical injection and one or more vertical vent wells are provided in the upper portion of the reservoir. Oxygen-enriched gas is injected down the injector well and ignited in the upper portion of the reservoir to create a combustion zone that reduces viscosity of oil in the reservoir as the combustion zone advances downwardly toward the horizontal production well. The reduced-viscosity oil drains into the horizontal production well under the force of gravity.
Canadian Patent 2,678,347 to Bailey discloses a pre-ignition heat cycle (PIHC) using cyclic steam injection and steam flood methods that improve the recovery of viscous hydrocarbons from a subterranean reservoir using an overhead in situ combustion process, referred to as combustion overhead gravity drainage (COGD). Bailey discloses a method where the reservoir well network includes one or more injection wells and one or more vent wells located in the top portion of the reservoir, and where the horizontal drain is located in the bottom portion of the reservoir.
The use of ISC as a follow up process to SAGD is disclosed in Canadian Patent 2,594,414 to Chhina et al. The disclosed hydrocarbon recovery processes may be utilized in oil sands reservoirs. Chhina discloses a process where a former steam injection well, used during the preceding SAGD recovery process, is used as an oxidizing gas injection well and where another former steam injection well, adjacent to the oxidizing gas injection well, is converted into a combustion gas production well. This results in the horizontal hydrocarbon production well being located below the horizontal oxidizing gas injection well and at least one combustion gas production well being spaced from the injection well by a distance that is greater than the spacing between hydrocarbon production well and the oxidizing gas injection well. Since the process disclosed by Chhina uses at least two wells pairs, ISC is initiated after the production well is sufficiently depleted of hydrocarbons to establish communication between the two well pairs.
Oil sands deposits may exist substantially in isolation, or may also include hydraulically contiguous mobile fluid zones that have relatively low bitumen saturation, for example they may have significant saturations of gas, water, or both. In such deposits, these mobile fluid zones can act as “thief zones” and have one or more undesirable effects on recovery methods. For example, oil sands deposits sometimes have a mobile fluid zone above the bitumen or heavy oils. In such deposits, the mobile fluid zone can have a significant saturation of gas which acts as the “thief zone” and when recovering the bitumen or heavy oils using a steam-based recovery process, a pressure in the gas zone that is lower than the steam pressure used in the recovery may be detrimental to the recovery since a flow of steam into the thief zone can lead to steam loss. As the steam chamber approaches the gas zone, and if the steam pressure is kept higher than the gas zone pressure, steam and possibly some of the oil may be pushed into the gas zone. Recovery of natural gas, in association with recovery of the bitumen or heavy oils, could also lower reservoir pressure, thereby reducing oil recovery, and may result in the recovery of oil being economically prohibitive. None of CA 1,304,287, U.S. Pat. No. 4,344,485, CA 2,096,034, U.S. Pat. No. 5,211,230, or CA 2,594,414 teach recovery of heavy oil from reservoirs having a gas zone.
Canadian Patent Application No. 2,594,413, titled “In situ Combustion in Gas Over Bitumen Formations”, relates to heavy oil recovery from reservoirs having a gas zone. In the disclosed process, air is injected into a gas zone which overlies an oil sand, in situ combustion is initiated within the gas zone, and the resulting combustion gases horizontally displace the natural gas to nearby production wells for recovery. The gas zone may be in pressure communication with the heavy oil and combustion gases may re-pressurize the natural gas reservoir, which may facilitate the recovery of the heavy oil using SAGD.
Canadian Patent Application No. 2,692,204 to Sanmiguel et al. (2010) titled “Gas-Cap Air Injection for Thermal Oil Recovery”, relates to heavy oil recovery from reservoirs having a gas zone. The disclosed process produces bitumen or heavy oil from a subsurface oil sands reservoir that is in fluid communication with an overlying gas zone. The method includes: providing an in situ combustion process in the overlying gas zone to create or expand a combustion front within the overlying gas zone, providing a thermal recovery process in the oil sands reservoir to create or expand a rising hot zone within the oil sands reservoir, and selectively operating the thermal recovery process or the in situ combustion process or both such that the rising hot zone does not intersect the overlying gas zone until the combustion front has moved beyond that portion of the overlying gas zone at the intersection. As noted on page 6 of CA 2,692,204, “If the thermal recovery process occurs early and the rising heated fluid . . . enters the gas zone 30 before the combustion front 90 has passed . . . the in situ combustion process within the gas zone 30 will be compromised or at least negatively impacted.”
U.S. Patent Applications No. 20120205096A1 and 20120205127A1 teach a method for displacing water from a porous geological formation where pressurized gas is injected into a zone and barrier wells are operated to achieve a hydraulic pressure barrier surrounding the zone. The gas displaces water downward within the zone such that water is produced at the water production wells.

SUMMARY

It is an object of the present disclosure to obviate or mitigate at least one disadvantage of previous processes that relate to heavy oil recovery from reservoirs having a mobile fluid zone above a bitumen zone.
According to one aspect, there is provided a process that includes: generating, in the bitumen zone and through a mobility enhancing process, a mobilized zone by recovering at least some of the original oil-in-place; injecting an oxidizing gas through an oxidizing gas injection well into the reservoir to support in situ combustion in the reservoir; generating fluid communication between the mobile fluid zone and the mobilized zone; and recovering hydrocarbons mobilized by the in situ combustion using a hydrocarbon production well that is in fluid communication with the mobile fluid zone and the mobilized zone, the in situ combustion propagating at least in the mobilized zone.
The mobility enhancing process may be a steam-assisted hydrocarbon recovery process, such as steam-assisted gravity drainage.
The mobility enhancing process may generate the fluid communication between the mobile fluid zone and the mobilized zone. Alternatively, the mobilized zone and the mobile fluid zone may not be in fluid communication before the in situ combustion process is initiated, and the in situ combustion may generate the fluid communication between the mobile fluid zone and the mobilized zone.
The process may further include producing combustion gases through a combustion gas production well. The hydrocarbon production well and the combustion gas production well may be a generally horizontal well pair. The generally horizontal well pair may be used to generate the mobilized zone through the mobility enhancing process.
Alternatively, the hydrocarbon production well and the oxidizing gas injection well may be a generally horizontal well pair. The generally horizontal well pair may be used to generate the mobilized zone through the mobility enhancing process. The process may further include producing combustion gases through a combustion gas production well. The combustion gas production well may be a former mobility enhancing process well that is in gaseous communication with the oxidizing gas injection well.
The oxidizing gas may be injected continuously or may be injected intermittently.
Water may be injected in addition to the oxidizing gas.
The mobile fluid zone may be a gas zone. The oxidizing gas may be injected into the gas zone or into the mobilized zone. The in situ combustion may propagate through the mobilized zone and through the mobile fluid zone.
Alternatively, mobile fluid zone may be a water zone. The oxidizing gas may be injected into the mobilized zone. The in situ combustion may generate steam from water in the water zone and the generated steam may aid in the mobilization of hydrocarbons in the reservoir.
According to another aspect, there is provided a process for hydrocarbon recovery from an oil sands reservoir having a gas zone above a bitumen zone. The process includes: utilizing a generally horizontal well pair to generate, through steam-assisted gravity drainage, a steam chamber in the bitumen zone that is in gaseous communication with the gas zone. The generally horizontal well pair includes: a generally horizontal segment of a hydrocarbon production well, and a generally horizontal segment of a steam injection well. The process includes injecting an oxidizing gas into the gas zone through an oxidizing gas injection well that includes an oxidizing gas injection segment. The oxidizing gas supports in situ combustion in the reservoir and the in situ combustion propagates at least in the steam chamber. The process further includes recovering hydrocarbons mobilized by the in situ combustion using the hydrocarbon production well; and producing combustion gas through the steam injection well. The generally horizontal segment of the steam injection well is disposed generally parallel to and spaced vertically above the horizontal segment of the hydrocarbon production well, and the injection segment of the oxidizing gas injection well is spaced generally above the segment of the hydrocarbon production well and generally above the segment of the steam injection well.
According to a further aspect, there is provided a process for hydrocarbon recovery from an oil sands reservoir having a water zone above a bitumen zone. The process includes: generating, in the bitumen zone and through steam-assisted gravity drainage, a steam chamber in the bitumen zone that is in fluid communication with the water zone; injecting an oxidizing gas through an oxidizing gas injection well into the steam chamber to support in situ combustion in the reservoir and the in situ combustion propagating at least in the steam chamber; generating steam by heating water in the water zone through the in situ combustion, the generated steam aiding in mobilizing hydrocarbons in the reservoir; and recovering hydrocarbons mobilized by the in situ combustion using a hydrocarbon production well that is in fluid communication with the water zone and the steam chamber.
Other aspects and features of the present disclosure will become apparent to those ordinarily skilled in the art upon review of the following description of specific embodiments in conjunction with the accompanying figures.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the present disclosure will now be described, by way of example only, with reference to the attached Figures. The patent or application file contains at least one drawing executed in color. Copies of this patent or patent application publication with color drawing(s) will be provided by the Office upon request and payment of the necessary fee.

FIG. 1 is an illustration of an exemplary well configuration which may be used in a process according to the present disclosure.

FIG. 2 is an illustration of another exemplary well configuration which may be used in a process according to the present disclosure.

FIG. 3 is an illustration of yet another exemplary well configuration which may be used in a process according to the present disclosure.

FIG. 4 illustrates an exemplary well configuration used in a computer simulation model.

FIG. 5 shows a graph illustrating the cumulative oil and gas production rates for the simulation model.

FIG. 6 illustrates the oil saturation profile at the start of the simulation.

FIG. 7 illustrates the temperature profile after one month of SAGD operation of the simulation.

FIG. 8 illustrates the temperature profile of the simulation model after 8 months of air injection.

FIG. 9 illustrates the oil saturation in the simulation model after 8 months of air injection.

FIG. 10 illustrates the mole fraction of oxygen in the gas phase after 8 months of air injection.

FIG. 11 illustrates the temperature profile after 22 months of air injection.

FIG. 12 illustrates the oil saturation in the simulation model after 82 months of air injection.

FIG. 13 illustrates the mole fraction of oxygen in the simulation model after 88 months of air injection.

FIG. 14 illustrates the temperature profile in the simulation model after 88 months of air injection.

DETAILED DESCRIPTION

For simplicity and clarity of illustration, reference numerals may be repeated among the figures to indicate corresponding or analogous elements. Numerous details are set forth to provide an understanding of the examples described herein. The examples may be practiced without these details. In other instances, well-known methods, procedures, and components are not described in detail to avoid obscuring the examples described. The description is not to be considered as limited to the scope of the examples described herein.
Heavy oil recovery techniques, such as SAGD, create mobilized zones in an oil sands reservoir, from which at least some of the original oil-in-place has been recovered. Steam injection methods such as cyclic-steam stimulation (CSS) and steam assisted gravity drainage (SAGD) are, to date, the most commercially successful in situ heavy oil and bitumen recovery methods. However, continued improvements and reduction in steam to oil ratio (SOR) are desirable. A mobilized zone created using a SAGD process may be considered to be a mobile zone chamber.
In situ combustion (ISC) has been used in combination with steam-based recovery to reduce the overall SOR. However, in viscous heavy oil reservoirs, such as oil sands reservoirs, the heavy oil lacks of sufficient fluid mobility and inhibits the injection of the oxidizing gas into the reservoir at sufficiently high rate to create the conditions for ignition and propagation of a combustion front. That is, heavy oil reservoirs do not have enough fluid mobility for the heavy oils to be displaced when a gas expands into the heavy oil reservoir.
One advantage of the process according to the present disclosure, over a process that uses ISC in combination with a mobility enhancing recovery process in a reservoir that does not include a mobile fluid zone, is that the presently disclosed process can be initiated earlier due to the presence of the mobile fluid zone above a bitumen zone. It is no longer required that the mobility enhancing recovery process reach a stage of maturity before switching to in situ combustion. This results in a faster process compared to reservoirs without a mobile fluid zone. For cases where the mobilized zone is generated using a steam-based mobility enhancing process, a faster switchover to in situ combustion may reduce the amount of water used to produce the same amount of hydrocarbons.
Within the context of the present disclosure, reference is made to zones or regions, such as bitumen zones, gas zones, and water zones. It will be understood by those skilled in the art that this does not require that the reservoir within a particular zone or region be saturated with the recited component. For example, a “bitumen zone” may contain both bitumen and water distributed throughout the porous structure. In a particular example of a “bitumen zone”, in a virgin rich oil sand, the pores may be 80 percent saturated with bitumen and 20 percent saturated with connate water.
In the context of the present disclosure, a “mobile fluid zone” is a zone with enough fluid mobility for at least some of the components of the zone to be displaced when a pressure differential is imposed into the mobile fluid zone. Mobile fluid zones may be, for example: gas zones and water zones. A mobile fluid zone may have less than 50% bitumen saturation. In an example, a mobile fluid zone may contain bitumen, water and gas distributed through the porous structure. In another example of a mobile fluid zone, the pores may contain predominantly gas with a relatively small bitumen saturation distributed throughout the porous medium. A mobile fluid zone may have sufficient hydrocarbons to support in situ combustion.
The present disclosure generally provides a process for hydrocarbon recovery from an oil sands reservoir having a mobile fluid zone above a bitumen zone. The process includes: generating, in the bitumen zone and through a mobility enhancing process, a mobilized zone by recovering at least some of the original oil-in-place; injecting an oxidizing gas through an oxidizing gas injection well into the mobile fluid zone or into the mobilized zone to support in situ combustion in the reservoir; generating fluid communication between the mobile fluid zone and the mobilized zone; and recovering hydrocarbons mobilized by the in situ combustion using a hydrocarbon production well that is in fluid communication with the mobile fluid zone and the mobilized zone, the in situ combustion propagating at least in the mobilized zone.
The mobility enhancing process may be a steam-assisted hydrocarbon recovery process, such as steam-assisted gravity drainage. As used herein, the term “mobility enhancing process well” should be understood to refer to a well which is used to provide a mobility enhancer, such as heat, solvent, or both, to promote the movement of the hydrocarbons toward the production well. Examples of a mobility enhancer include: steam, hot water, methane, hydrocarbon solvents, a heat source, or combinations thereof. An example of a steam-assisted hydrocarbon recovery well pair includes: a SAGD well pair. An example of a steam-assisted hydrocarbon recovery well includes: cyclic-steam stimulation well. An example of a non-steam based recovery method includes: electromagnetic heating.
The fluid communication between the mobile fluid zone and the mobilized zone may be generated by the mobility enhancing process before the in situ combustion. Alternatively, the in situ combustion may be started when the mobilized zone and the mobile fluid zone are not in fluid communication, and the fluid communication between the mobile fluid zone and the mobilized zone may be generated by the in situ combustion.
The in situ combustion propagates at least in the mobilized zone. Since the in situ combustion in the mobilized zone is fueled by residual hydrocarbons in the oil sands deposits, the hydrocarbons in the oil sands deposit may be un-depleted, or may be partially depleted prior to the process disclosed herein.
The hydrocarbon production well may be a generally horizontal well, a generally vertical well, or a generally inclined well. The hydrocarbon production well may have a combination of different segments which are independently generally vertical, generally inclined, or generally horizontal. The hydrocarbon production well may be located anywhere in fluid communication with the mobilized zone. For example, the hydrocarbon production well may be close to the bottom of the hydrocarbon deposit to collect the mobilized hydrocarbons that flow toward the bottom due to gravity.
The oxidizing gas injection well may be located such that an oxidizing gas injection segment is located in gaseous communication with the mobilized zone. For example, the oxidizing gas injection segment may be in the mobilized zone, or may be in the mobile fluid zone if the mobile fluid zone is a gas zone.
The oxidizing gas injection well may be a generally horizontal well, a generally vertical well, or a generally inclined well. The oxidizing gas injection well may have a combination of different segments which are independently generally vertical, generally inclined, or generally horizontal. The oxidizing gas injection well may be completed with one or more discrete injection locations. In some examples, the oxidizing gas injection well injects the oxidizing gas along the length of a generally horizontal production well. This may be accomplished, for example, by using a generally horizontal oxidizing gas injection well that is parallel to a generally horizontal production well and that has a plurality of discrete oxidizing gas injection locations; or by using a plurality of vertical oxidizing gas injection wells aligned along the length of a generally horizontal production well.
Combustion gases generated from the in situ combustion may be produced through a combustion gas production well, or through the hydrocarbon production well. If a combustion gas production well is used, it may be a generally horizontal well, a generally vertical well, or a generally inclined well. The combustion gas production well may have a combination of different segments which are independently generally vertical, generally inclined, or generally horizontal. The combustion gas production well may be located in the mobile fluid zone, or in the mobilized zone.
The hydrocarbon production well may be a well that is unrelated to the well or wells used to generate the mobilized zone. For example, a single well may be used as a mobility enhancing process well to generate the mobilized zone and a different well may be used as the hydrocarbon production well to recover hydrocarbons mobilized by the in situ combustion. In such an example, the mobility enhancing process well may be a well used for cyclic steam stimulation.
Alternatively, the hydrocarbon production well may be the production well in a well or wells used to generate the mobilized zone. For example, a single well may be used to generate the mobilized zone, for example using cyclic steam stimulation, and that same well may be used as the hydrocarbon production well to recover hydrocarbons mobilized by the in situ combustion. In another example, a well pair may be used to generate the mobilized zone where: (1) the former hydrocarbon production well from the well pair may be used as the hydrocarbon production well to recover the hydrocarbons mobilized by the in situ combustion, and (2) the former mobility enhancing process well from the well pair may be used as the oxidizing gas injection well or as the combustion gas production well.
In examples where the former hydrocarbon recovery well pair is a generally horizontal well pair and the former mobility enhancing process well is used as the combustion gas production well, the oxidizing gas injection well may inject the oxidizing gas along the length of the generally horizontal well pair. This may be accomplished, for example, by using a generally horizontal oxidizing gas injection well that is parallel to the generally horizontal well pair and that has a plurality of discrete oxidizing gas injection locations; or by using a plurality of vertical oxidizing gas injection wells aligned along the length of the generally horizontal well pair.
In processes that use steam as the mobility enhancer, such as SAGD, steam is injected into the steam injection well to mobilize the hydrocarbons and create a steam chamber in the reservoir, around and above the generally horizontal segment. It may be beneficial if the oxidizing gas injection segment is located generally above both the steam injection well and the hydrocarbon production well. Wells having such a configuration take advantage of gravity segregation between the oxidizing gas and the liquids, including the hydrocarbons. By virtue of the density difference between gases and liquids, the liquids, including the hydrocarbons, tend to accumulate in the lower portion of the chamber, inhibiting fingering of the oxidizing gas into the hydrocarbon production wells. The oxidizing gas is generally consumed at the combustion front. Thus, travel of oxidizing gas ahead of the combustion front, into a colder region of the chamber, is inhibited. This is beneficial as travel of oxidizing gas ahead of the combustion front may induce low temperature oxidation reactions and cause blocking problems in the reservoir. A “blocking problem” would be understood to refer to non-mobile oil blocking the movement of oxidizing gases to the combustion front.
It should be understood that an oxidizing gas injection well being disposed “generally vertically above” or “generally above” a steam injection well refers to the injection segment of an oxidizing gas injection well being less than 75° from a vertical line extending through the steam injection well. In particular embodiments, the injection segment of an oxidizing gas injection well is less than about 60° from the vertical line. In preferred embodiments, the injection segment of an oxidizing gas injection well is less than about 45° from the vertical line. The terms “directly vertically above” and “directly above” refer to embodiments where the injection segment of an oxidizing gas injection well is less than about 5° from a vertical line extending through the steam injection well. The terms would similarly denote the spatial relationship of any other two wells.
In processes that use steam as the mobility enhancer, such as SAGD, additional components may be added to the injected steam. For example: light hydrocarbons, such as C3 through C10 alkanes, may optionally be injected with the steam. The volume of light hydrocarbons that are injected is relatively small compared to the volume of steam injected. The addition of light hydrocarbons is referred to as a solvent-assisted process (SAP). SAGD and SAP processes are both examples of mobility enhancing processes. The SAGD or SAP processes may also be augmented or enhanced by inclusion of other substances, such as: non-condensing gases, for example: nitrogen or oxygen; surfactants; steam additives; or any combination thereof. Viscous hydrocarbons in the bitumen zone are heated and mobilized and the mobilized hydrocarbons drain, under the effects of gravity. The mobilized hydrocarbons are collected and produced from the hydrocarbon production well.
A mobility enhancing process may be performed for a period of time until the mobilized zone is in fluid communication with the mobile fluid zone. When the mobility enhancing process is SAGD, this may be achieved by injecting steam through a steam injection well and recovering oil until the steam chamber is in fluid communication with the mobile fluid zone. Sensors such as pressure and temperature sensors located in the steam injection well, in the hydrocarbon production well, in the oxidizing gas injection well, or any combination thereof, may be utilized to detect when the steam chamber is in fluid communication with the mobile fluid zone. Alternatively or additionally, observation wells drilled into the reservoir may be utilized to determine that the steam injected is in fluid communication with the mobile fluid zone. Steam front monitoring may also be utilized to determine that the injected steam is in fluid communication with the mobile fluid zone. Sensors and monitoring methods may also be used when the mobility enhancing process is a process other than SAGD.
Prior to ignition to start ISC in the oxidizing gas injection well, steam may be injected into the oxidizing gas injection wellbore to remove liquid hydrocarbons surrounding the wellbore. This injected steam raises the temperature of part of the reservoir, for example, to about 150° C. Alternatively, a volatile oil mixture may be added to the formation and then displaced by steam injection followed by injection of a non-condensing gas, for example nitrogen. For example, steam may be injected for about one day, followed by nitrogen injection for about one day. The steam, or steam and subsequent nitrogen, is used to reduce the amount of combustible materials from the immediate vicinity of the oxidizing gas injection wellbore and thereby reduce high temperature exposure and consequent damage to the steel.
ISC is carried out by injecting an oxidizing gas through the oxidizing gas injection well. The in situ combustion propagates at least in the mobilized zone. The oxidizing gas may be injected continuously for continuous combustion, or may be injected intermittently. Combustion may be initiated utilizing an artificial igniter, such as a downhole heater, or by using spontaneous ignition. The oxidizing gas that is injected may be, for example, air, enriched air, diluted air, or any other suitable gas including oxygen. The in situ combustion may be managed to mobilize hydrocarbons in the heavy oil by controlling: the rate, the pressure, or both of oxidizing gas injected through the oxidizing gas injection well; the rate, the pressure, or both of production of combustion gases from the former steam injection well; the rate, the pressure, or both of hydrocarbon production from the hydrocarbon production well; or any combination thereof.
Optionally, water may be injected in addition to the oxidizing gas. For example, water may be injected at the same time as, or in sequence with, the oxidizing gas. The water may be injected through the same well as the oxidizing gas, or through separate wells. Injected water, water already present in the reservoir, or both may result in a wet combustion process and steam generation. The generated steam may facilitate the flow of heated hydrocarbons to the hydrocarbon production well since the generated steam promotes heat transfer in the oil sands reservoir.
In processes that use a former SAGD steam injection well as the combustion gas production well, the oxidizing gas is injected through the oxidizing gas injection well and into the reservoir. The generated combustion gases are produced from the former steam injection well, now the combustion gas production well, since they are driven into the generally horizontal segment of the steam injection well. The hydrocarbons that are mobilized as a result of the combustion process drain to the generally horizontal segment and are recovered through the hydrocarbon production well. Thus, the steam injection well and the hydrocarbon production well utilized in the SAGD process are utilized in this example of the process to collect the combustion gases and to produce the mobilized hydrocarbons, respectively. In this way, the SAGD well pair is advantageously re-utilized.
Infill producer wells, which may have been added as concurrent supplements to the SAGD process, are not required for the ISC process but may be used as hydrocarbon production wells.
A benefit to utilizing a combustion gas production well that is separate from a hydrocarbon production well, is that the hydrocarbons that are produced are separated from the combustion gases downhole, thereby reducing the chance of oxidizing gas and combustion gases communicating with the hydrocarbon production well. That is, it reduces the chance that oxidizing gases, combustion gases, or both will escape via the hydrocarbon production well. This reduction may result in the combustion front being more easily controlled. This reduction may additionally reduce high volumes of combustion gases flowing into the hydrocarbon production well, which could restrict the flow of hydrocarbons into the hydrocarbon production well. Corrosion of metals, such as well tubes, and other well apparatus, may be mitigated and surface facilities design may be facilitated as the gases and hydrocarbons are substantially separated downhole. Notwithstanding the desirability of collecting these fluid streams at separate wells, it should be understood that the well which collects the combustion gases may also produce some hydrocarbons. Correspondingly, the hydrocarbon production well may produce some combustion gases.
The ISC process that is carried out, referred to as top-down in situ combustion, takes advantage of gravity segregation between the oxidizing gas and the liquids, including the hydrocarbons. By virtue of the density difference between gases and liquids, the liquids, including the hydrocarbons, tend to accumulate in the lower portion of the chamber, inhibiting fingering of the oxidizing gas into the hydrocarbon production wells. The oxidizing gas is generally consumed at the combustion front. Thus, travel of oxidizing gas ahead of the combustion front, into a colder region of the chamber, is inhibited. This is beneficial as travel of oxidizing gas ahead of the combustion front may induce low temperature oxidation reactions and cause blocking problems in the reservoir. A “blocking problem” would be understood to refer to non-mobile oil blocking the movement of oxidizing gases to the combustion front.
For reservoirs where the mobile fluid zone is a gas zone, the gas zone may have sufficient hydrocarbons to support in situ combustion. The in situ combustion may be initiated once the mobilized zone is in gaseous communication with the gas zone, or may be initiated in order to generate gaseous communication between the mobilized zone and the gas zone. The in situ combustion may propagate in both the mobilized zone and in the gas zone. Since the in situ combustion in the gas zone is fueled by hydrocarbons within the gas zone, the gas zone may be un-depleted, or may be partially depleted prior to the process disclosed herein.
When the mobile fluid zone is a gas zone, the pressure in the gas zone may be greater than, about the same as, or less than the pressure of the gasses in the mobilized zone. It may be desirable to operate the mobility enhancing process at a pressure lower than the pressure of the gas in the gas zone in order to expedite gaseous communication between mobilized zone and the gas zone.
The oil sands deposit may have mobile fluid zones comprising non-combustible gases, such as air zones, that are formed as a result of natural depletion of the hydrocarbons. The oil sands deposits may have mobile fluid zones that been formed by displacing one mobile fluid with another mobile fluid. For example a liquid, such as water, may be displaced from the mobile fluid zone using pressurized gas injected into the mobile fluid zone. Specific examples of methods of formation of such mobile fluid zones are described in U.S. Patent Applications No. 20120205096A1 and 20120205127A1.
In processes that use injected steam as the mobility enhancer and the mobile fluid zone is a gas zone, it may be preferable to drill the oxidizing gas injection well prior to the steam chamber being in gaseous communication with the oxidizing gas injection well in order to avoid drilling through a high temperature, high pressure reservoir. For example, the oxidizing gas injection well may be drilled into the gas zone before the steam chamber is in gaseous communication with the gas zone. In another example, the oxidizing well may be drilled into a portion of the reservoir that becomes a part of the steam chamber.
For reservoirs where the mobile fluid zone is a water zone, the in situ combustion may be initiated once the mobilized zone is in fluid communication with the water zone. The in situ combustion may propagate primarily in the mobilized zone and may produce steam through heating water in the water zone. The produced steam may aid in the mobilization of hydrocarbons in the reservoir.
In one exemplary process according to the present disclosure, the process includes generating a steam chamber using a steam-assisted hydrocarbon recovery process, such as SAGD, in a bitumen zone that is below a gas zone. The generated steam chamber is in gaseous communication with the gas zone. Oxidizing gas is injected in the gas zone to support in situ combustion in the reservoir. The oxidizing gas is injected using an oxidizing gas injection well. In this example, the former steam injection well used in the steam-assisted hydrocarbon recovery process is used as the combustion gas production well, and the former hydrocarbon production well used in the steam-assisted hydrocarbon recovery process is used as the hydrocarbon production well for the in situ combustion. The in situ combustion propagates at least in the mobilized zone. In this example, the former steam injection well and the former hydrocarbon production well are a generally horizontal well pair, and the oxidizing gas injection well is a generally horizontal well that injects the oxidizing gas along the length of the generally horizontal well pair through a plurality of discrete oxidizing gas injection locations.
In another exemplary process according to the present disclosure, the process includes generating a steam chamber using a steam-assisted hydrocarbon recovery process, such as SAGD, in a bitumen zone that is below a water zone. The generated steam chamber is in fluid communication with the water zone. Oxidizing gas is injected in the steam chamber to support in situ combustion in the reservoir. The oxidizing gas is injected using an oxidizing gas injection well. The in situ combustion propagates at least in the steam chamber. The in situ combustion may produce steam through heating the water in the water zone. The produced steam may aid in the mobilization of hydrocarbons in the water zone, in the mobilized zone, or both. In this example, the former steam injection well used in the steam-assisted hydrocarbon recovery process is used as the combustion gas production well, and the former hydrocarbon production well used in the steam-assisted hydrocarbon recovery process is used as the hydrocarbon production well for the in situ combustion.
In still another example of a process according to the present disclosure, the mobile fluid zone is a gas zone and the process includes generating a mobilized zone through a mobility enhancing process, and injecting an oxidizing gas through an oxidizing gas injection well into the gas zone or into the mobilized zone, the oxidizing gas supporting in situ combustion in the reservoir. The process includes generating gaseous communication between the gas zone and the generated mobilized zone. The oxidizing gas is injected using a former mobility enhancing process well. Another former mobility enhancing process well that is in gaseous communication with the oxidizing gas injection well is used as a combustion gas production well. The in situ combustion propagates at least in the mobilized zone. Hydrocarbons mobilized through the in situ combustion are removed from the bottom of the reservoir using the former hydrocarbon production well used in the mobility enhancing process. Additional gas production wells may be drilled in the gas zone or in the mobilized zone.
In yet another example of a process according to the present disclosure, where the mobile fluid zone is a gas zone, the process includes: using a generally horizontal well pair to generate, through steam-assisted gravity drainage, a steam chamber that is in gaseous communication with the gas zone, where the generally horizontal well pair includes: a generally horizontal segment of a hydrocarbon production well, and a generally horizontal segment of a steam injection well; injecting an oxidizing gas into the gas zone through an oxidizing gas injection well including an oxidizing gas injection segment, the oxidizing gas supporting in situ combustion in the reservoir and the in situ combustion propagating at least in the steam chamber; recovering hydrocarbons mobilized by the in situ combustion using the hydrocarbon production well; and producing combustion gas through the steam injection well. In such an example, the generally horizontal segment of the steam injection well is disposed generally parallel to and spaced vertically above the horizontal segment of the hydrocarbon production well, and the injection segment of the oxidizing gas injection well is spaced generally above the segment of the hydrocarbon production well and generally above the segment of the steam injection well.
Although examples discussed above discuss a steam-assisted hydrocarbon recovery process, and specifically SAGD, being carried out before in situ combustion, it should be understood that mobility enhancing processes other than steam-assisted recovery may be used. For example, hot water, methane, hydrocarbon solvents, a heat source, or combinations thereof may alternatively be used to establish fluid communication between the oxidizing gas injection well and the hydrocarbon recovery well.
One specific example of a generally horizontal well pair which may be used in the process disclosed herein is illustrated in FIG. 1. Although the illustration and corresponding discussion relates specifically to SAGD, it should be understood that other mobility enhancing processes may be used and, accordingly, the discussed steam injection well may be substituted with another “mobility enhancing process well” and the discussed steam chamber would be a corresponding “mobilized zone”. Further, although the illustration and corresponding discussion relates specifically to gas zones located above the bitumen zone, it should be understood that the process would be applicable in reservoirs having other mobile fluid zones.
As illustrated in FIG. 1, the hydrocarbon production well includes a generally horizontal segment 10 that extends near the base or bottom of the bitumen zone. The steam injection well also includes a generally horizontal segment 16 that is disposed generally parallel to and is spaced generally vertically above the horizontal segment 10 of the hydrocarbon production well.
The oxidizing gas injection well 18 is located with the gas injection segment in the gas zone 20 such that the segment extends generally parallel to the generally horizontal segments 16 of steam injection well. The illustration in FIG. 1 shows the reservoir before gaseous communication has been generated between the gas zone 20 and the steam chamber 22.
It would be understood that an oxidizing gas injection well could provide oxidizing gas to mobilize hydrocarbons that are produced through more than one hydrocarbon production well, as illustrated in FIG. 2. The illustration in FIG. 2 shows the reservoir before gaseous communication has been generated between the gas zones 20 and the steam chambers 22.
It would also be understood that a plurality of well pairs may be utilized at spaced-apart locations in the reservoir and a plurality of oxidizing gas injection wells may be utilized to provide oxidizing gas to mobilize hydrocarbons. It should be understood that it is not necessary to match the number of oxidizing gas injection wells to the number of steam injections wells. For example, two oxidizing gas injection wells may be used in combination with three steam injection well, as illustrated in FIG. 3. In this example, three SAGD well pairs and two oxidizing gas injection wells 18 located with the gas injection segment in the gas zone 20 such that the injection segment extends generally parallel to the generally horizontal segments 16 of steam injection well.
FIG. 3 illustrates the reservoir after gaseous communication has been generated between the gas zone 20 and the steam chambers 22. As illustrated, the steam chamber on the left and the steam chamber in the middle are both in direct gaseous communication with each other and are in direct gaseous communication with the gas zone. The steam chamber on the right is in direct gaseous communication with the gas zone, and is in gaseous communication with the other two steam chambers through the gas zone.

EXAMPLES

Example 1

A computer simulation was run to model an oil sands recovery process where two SAGD well pairs and one gas producer well were used to recover hydrocarbons. In the simulation, the two oxidizing gas injection wells were located directly vertically above the two SAGD well pairs and the gas producer well was located within the gas zone, equally laterally spaced apart from the two SAGD well pairs.
The configuration is illustrated in FIG. 4.
FIG. 5 shows a graph illustrating the cumulative oil and gas production rates for the simulation model.
FIG. 6 illustrates the oil saturation profile at the start of the simulation (2000-01-01). Original oil saturation in the gas zone is 20%, gas saturation is 60% and connate water is 20%. The initial reservoir temperature is 8° C.
FIG. 7 shows the temperature profile after one month of SAGD operation (2000-02-01). The reservoir has reached a maximum temperature of 170° C. and communication has been established between the mobilized zones created by the SAGD process and the overlying gas zone.
After one month of SAGD, the SAGD process is finalized and in situ combustion is instigated in the reservoir by injecting air into the oxidizing gas injection wells. The previous steam injector is shut in and the gas producer in the gas zone starts operating.
FIG. 8 shows the temperature profile at 2000-09-01 after 8 months of air injection. The combustion front has been ignited and is propagating towards the hydrocarbon producing wells as indicated by the elevated temperature profile.
FIG. 9 shows the oil saturation in the simulation model at 2000-09-01. Oil saturation around the air injector is preferably zero when the combustion front is initiated as the residual oil saturation is consumed as fuel during the in situ combustion process.
FIG. 10 shows the mole fraction of oxygen in the gas phase at 2000-09-01. The oxygen has been consumed by the combustion process at the vicinity of the oxidizing gas injection wells.
FIG. 11 shows the temperature profile at 2001-12-01. The combustion front is advancing towards the gas producer and expanding both in the gas zone as well as in the heavy oil zone.
FIG. 12 shows the oil saturation for the simulation model at 2006-12-01.
FIG. 13 shows the mole fraction of oxygen for the simulation model at 2007-06-01.
FIG. 14 shows the temperature profile for the simulation model at 2007-06-01. The figures illustrate that the combustion front has progressed significantly into the heavy oil zone.
The described examples are to be considered in all respects only as illustrative and not restrictive. The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole. All changes that come with meaning and range of equivalency of the claims are to be embraced within their scope.

Claims

What is claimed is:

1. A process for hydrocarbon recovery from an oil sands reservoir having a mobile fluid zone above a bitumen zone, the process comprising:

generating, in the bitumen zone and through a mobility enhancing process, a mobilized zone by recovering at least some of the original oil-in-place;

injecting an oxidizing gas through an oxidizing gas injection well into the reservoir to support in situ combustion in the reservoir;

generating fluid communication between the mobile fluid zone and the mobilized zone; and

recovering hydrocarbons mobilized by the in situ combustion using a hydrocarbon production well that is in fluid communication with the mobile fluid zone and the mobilized zone, the in situ combustion propagating at least in the mobilized zone.

2. The process according to claim 1, wherein the mobility enhancing process is a steam-assisted hydrocarbon recovery process.

3. The process according to claim 2, wherein the steam-assisted hydrocarbon recovery process is steam-assisted gravity drainage.

4. The process according to claim 1, wherein the mobility enhancing process generates the fluid communication between the mobile fluid zone and the mobilized zone.

5. The process according to claim 1, wherein the mobilized zone and the mobile fluid zone are not in fluid communication before the in situ combustion process is initiated, and wherein the in situ combustion generates the fluid communication between the mobile fluid zone and the mobilized zone.

6. The process according to claim 1, further comprising producing combustion gases through a combustion gas production well.

7. The process according to claim 6, wherein the hydrocarbon production well and the combustion gas production well are a generally horizontal well pair.

8. The process according to claim 7, wherein the generally horizontal well pair is used to generate the mobilized zone through the mobility enhancing process.

9. The process according to claim 1, wherein the hydrocarbon production well and the oxidizing gas injection well are a generally horizontal well pair.

10. The process according to claim 9, wherein the generally horizontal well pair is used to generate the mobilized zone through the mobility enhancing process.

11. The process according to claim 10, further comprising producing combustion gases through a combustion gas production well.

12. The process according to claim 11, wherein the combustion gas production well is a former mobility enhancing process well that is in gaseous communication with the oxidizing gas injection well.

13. The process according to claim 1, wherein the oxidizing gas is injected continuously.

14. The process according to claim 1, wherein the oxidizing gas is injected intermittently.

15. The process according to claim 1, wherein water is injected in addition to the oxidizing gas.

16. The process according to claim 1 wherein the mobile fluid zone is a gas zone.

17. The process according to claim 16, wherein the oxidizing gas is injected into the gas zone.

18. The process according to claim 16, wherein the oxidizing gas is injected into the mobilized zone.

19. The process according to claim 16, wherein the in situ combustion propagates through the mobilized zone and through the mobile fluid zone.

20. The process according to claim 1 wherein the mobile fluid zone is a water zone.

21. The process according to claim 20, wherein the oxidizing gas is injected into the mobilized zone.

22. The process according to claim 20, wherein the in situ combustion generates steam from water in the water zone and the generated steam aids in the mobilization of hydrocarbons in the reservoir.

23. A process for hydrocarbon recovery from an oil sands reservoir having a gas zone above a bitumen zone, the process comprising:

utilizing a generally horizontal well pair to generate, through steam-assisted gravity drainage, a steam chamber in the bitumen zone that is in gaseous communication with the gas zone, wherein the generally horizontal well pair comprises: a generally horizontal segment of a hydrocarbon production well, and a generally horizontal segment of a steam injection well;

injecting an oxidizing gas into the gas zone through an oxidizing gas injection well including an oxidizing gas injection segment, the oxidizing gas supporting in situ combustion in the reservoir and the in situ combustion propagating at least in the steam chamber;

recovering hydrocarbons mobilized by the in situ combustion using the hydrocarbon production well; and

producing combustion gas through the steam injection well;

the generally horizontal segment of the steam injection well being disposed generally parallel to and spaced vertically above the horizontal segment of the hydrocarbon production well, and the injection segment of the oxidizing gas injection well being spaced generally above the segment of the hydrocarbon production well and generally above the segment of the steam injection well.

24. A process for hydrocarbon recovery from an oil sands reservoir having a water zone above a bitumen zone, the process comprising:

generating, in the bitumen zone and through steam-assisted gravity drainage, a steam chamber in the bitumen zone that is in fluid communication with the water zone;

injecting an oxidizing gas through an oxidizing gas injection well into the steam chamber to support in situ combustion in the reservoir and the in situ combustion propagating at least in the steam chamber;

generating steam by heating water in the water zone through the in situ combustion, the generated steam aiding in mobilizing hydrocarbons in the reservoir;

and recovering hydrocarbons mobilized by the in situ combustion using a hydrocarbon production well that is in fluid communication with the water zone and the steam chamber.