CA2767846A1

CA2767846A1 - Microbial enhanced pre-treatment of carbonate reservoirs for in situ heavy hydrocarbon recovery

Info

Publication number: CA2767846A1
Application number: CA2767846A
Authority: CA
Inventors: Carolina Diaz-Goano
Original assignee: Suncor Energy Inc
Current assignee: Suncor Energy Inc
Priority date: 2012-02-03
Filing date: 2012-02-03
Publication date: 2013-08-03
Also published as: WO2013113126A1; US20150053407A1; CA2863617A1

Abstract

Processes, systems and techniques are provided for treating a carbonate reservoir with a microbial stimulation fluid at a temperature allowing microbial conversion of the fluid to produce a byproduct to promote dissolution of carbonate compounds and increasing the porosity and/or permeability of the carbonate reservoir. For example, the process may include injecting the microbial stimulation fluid into a region of a carbonate reservoir, wherein the region includes heavy hydrocarbons and a microbial culture; temperature treating the region to a reservoir temperature that allows a microbial metabolic pathway of the microbial culture to convert the microbial stimulation fluid and generate a byproduct, such as acetic bioacid, to promote dissolution of carbonate compounds in the region;
soaking the region for a period during which carbonate compounds dissolve and porosity of the region is increased; and following the soak period, recovering heavy hydrocarbons from the region of increased porosity.

Description

MICROBIAL ENHANCED PRE-TREATMENT OF CARBONATE
RESERVOIRS FOR IN SITU HEAVY HYDROCARBON RECOVERY
FIELD OF THE INVENTION
The present invention generally relates to the field of in situ hydrocarbon recovery and more particularly to processes and systems for microbial enhanced pre-treatment of a carbonate reservoir for in situ heavy hydrocarbon recovery.
BACKGROUND
While oil sands reservoirs have been commercially exploited for several decades, carbonate reservoirs have been challenging in terms of efficiently recovering hydrocarbons due to particular characteristics of carbonate reservoirs.
Oil sands reservoirs, on the one hand, are primarily composed of a matrix of unconsolidated sand, which is a naturally occurring granular material mainly composed of silica (Si02), with hydrocarbons occurring in the sand matrix. Oil sands reservoirs also tend to display water-wet conditions, meaning that a thin film of water coats the surface of the sand particles and hydrocarbons surround the inner water coating.
Carbonate reservoirs, on the other hand, are primarily composed of carbonate compounds, such as calcium carbonate (CaCO3), with hydrocarbons present throughout the carbonate rock matrix. Carbonate reservoirs are more fractured and heterogeneous while being less permeable and porous compared to oil sands reservoirs. Heavy hydrocarbon recovery from carbonate reservoirs is particularly challenging due to the high viscosity of such heavy hydrocarbons combined with the properties of the carbonate reservoirs.
Carbonate reservoirs including heavy hydrocarbons, such as bitumen, are nevertheless a significant resource, particularly in Alberta, Canada. For example, approximately 23% of the total of 1,800 billion barrels of bitumen in place in Alberta is found in the Grosmont formation, a stratigraphical unit in the Western Canadian Sedimentary Basin (WCSB) including sedimentary dolomite and limestone. Bitumen production from this formation is complicated by carbonate reservoir characteristics such as fractures, low permeability and low porosity. In addition, production may also be challenging where carbonate rock is oil-wet.
Carbonate reservoir matrices have lower permeability and porosity than oil sands. By way of comparison, some areas of carbonate reservoirs may have permeabilities of about 1-10 millidarcies (mD) while oil sands reservoirs often have permeabilities in the range of 3,000-5,000 mD or even up to 10,000 mD.
Thus, carbonate reservoirs can have areas with a low permeability that are two, three or four orders of magnitude smaller than for some oil sands reservoirs.
It should also be noted that carbonate reservoirs include fractures and holes in the carbonate rock. Carbonate reservoirs are naturally fractured geologic formations characterized by heterogeneous porosity and permeability distributions. Fractures may include micro-fractures, mille-fractures or macro-fractures. The fractures and holes may also contain bitumen, which is difficult to access due to the low permeability and porosity of surrounding carbonate rock. Carbonate reservoirs also include fragments of marine organisms, skeletons, coral, algae, and the like, adding to the heterogeneity of such reservoirs.
The heavy hydrocarbons in carbonate reservoirs, such as those in the Grosmont formation, include residues from extensive in situ biodegradation by an active microbial community.
In oil sands reservoirs, bitumen has been traditionally recovered by two main methods: surface mining and in situ recovery. However, in carbonate formations in situ recovery is particularly challenging due to the nature of such reservoirs, in particular the low permeability and low porosity typical of such formations. Enhanced in situ recovery processes in oil sands reservoirs have used heat, steam injection and/or solvent injection to increase the mobility of the heavy hydrocarbons (e.g., Steam Assisted Gravity Drainage (SAGO), Vapor Extraction Process (VAPEX), Cyclic Steam Stimulation (CSS), Fracture assisted Cyclic Steam Stimulation (FCSS), and flooding).
The low permeability and porosity of carbonate reservoirs creates challenges for the injection of mobilizing fluids, such as steam and solvents. Impaired injectivity, in turn, reduces the ability of the injected mobilizing fluid to access and mobilize the heavy hydrocarbons and therefore reduces the efficiency and productivity of the recovery process.
SUMMARY OF THE INVENTION
The present invention provides processes, systems and techniques for treating a carbonate reservoir with a microbial stimulation fluid at a temperature allowing microbial conversion of the microbial stimulation fluid to produce a byproduct to promote dissolution of carbonate compounds and increasing the porosity and permeability of the carbonate reservoir.
There is provided a process including injecting a microbial stimulation fluid into a region of a carbonate reservoir, wherein the region includes heavy hydrocarbons and a microbial culture; temperature treating the region to a reservoir temperature that allows a microbial metabolic pathway of the microbial culture to convert the microbial stimulation fluid and generate a byproduct to promote dissolution of carbonate compounds in the region;
soaking the region for a soak period during which carbonate compounds dissolve and porosity of the region is increased; and following the soak period, recovering heavy hydrocarbons from the region of increased porosity.
The microbial stimulation fluid may include CO2. The microbial stimulation fluid may further include H2.
The process may further include preheating the microbial stimulation fluid to a heated temperature, thereby producing a preheated microbial stimulation fluid, before injection; wherein temperature treating the region includes heating the region with heat conducted from the preheated microbial stimulation fluid. Recovering heavy hydrocarbons may include subjecting the region to a SAGD recovery process and/or subjecting the region to a CSS
recovery process.
The process may further include identifying the microbial culture indigenous to the region of the carbonate reservoir; and selecting the microbial stimulation fluid based on the identification and such that the microbial metabolic pathway will convert the microbial stimulation fluid to generate the byproduct that promotes dissolution of carbonate compounds in the region.
There is also provided a process for pre-treating a carbonate reservoir including heavy hydrocarbons in preparation for hydrocarbon recovery, including injecting a microbial stimulation fluid into a region of the carbonate reservoir wherein the region includes a microbial culture, wherein the region is at a reservoir temperature allowing a microbial metabolic pathway of the microbial culture to convert the microbial stimulation fluid into a byproduct to promote dissolution of carbonate compounds in the region; and wherein the dissolution of the carbonate compounds increases porosity and permeability of the region.
The carbonate reservoir may include a stratigraphical unit with sedimentary dolomite and limestone. The region of the carbonate reservoir may include a dense limestone matrix and at least a portion of the heavy hydrocarbons may be in the dense limestone matrix. The region of the carbonate reservoir may have a low permeability between 1 mD and 200 mD, or between 1 mD and 10 mD.
The microbial stimulation fluid may be gaseous. The microbial stimulation fluid may include 002. The microbial stimulation fluid may include H2. The process may further include co-injecting a mixture including the CO2 and the H2 as the microbial stimulation fluid. The microbial stimulation fluid may further include an additional microbial nutrient.
The microbial metabolic pathway may convert the CO2 into a bioacid as the byproduct. The microbial culture may include an acetogen and the metabolic pathway may include the Wood-Ljungdahl pathway, thereby producing acetic bioacid as the byproduct. The microbial stimulation fluid may include H2 and CO2 in a molar proportion in accordance with the Wood-Ljungdahl pathway for production of the acetic bioacid. The microbial stimulation fluid may include water.
The CO2 may be derived from an in situ hydrocarbon recovery operation, a bitumen mining operation, a bitumen extraction operation, a hydrocarbon upgrading operation, a power production operation, or a combination thereof.
At least part of the CO2 may be sequestered in the carbonate reservoir.
The process may further include heating the region of the carbonate reservoir to the reservoir temperature by injecting the microbial stimulation fluid at a fluid temperature sufficient to heat the region without detrimentally affecting the microbial culture. The temperature of the microbial stimulation fluid may be between 15 C and 80 C, or between 20 C and 60 C, or above 45 C.
The process may include heating the region of the carbonate reservoir by a separate heat source from the microbial stimulation fluid.
The process may include heating of the region by a separate heat source by operating a thermal in situ recovery operation adjacent to the region, before or during the pre-treatment process. The hydrocarbon recovery may be selected from Steam Assisted Gravity Drainage (SAGD), Vapor Extraction Process (VAPEX), Cyclic Steam Stimulation (CSS), Fracture assisted Cyclic Steam Stimulation (FOSS), Flooding with steam, water or solvents, solvent assisted SAGD, other solvent assisted processes, surfactant assisted processes, in situ combustion processes, and combinations thereof.
The heating of the region by a separate source may include injecting a heating fluid into or adjacent to the region and/or operating a heating device in or adjacent to the region.
The microbial culture may consist of an indigenous in situ microbial culture.
The process may also include identifying one or more target zones defining the region of the carbonate reservoir, wherein the target zones include the microbial culture and the microbial stimulation fluid is injected into the target zones. Target zones may be identified based on having a permeability of at most 100 mD. The target zones may be identified based on including an oil-wet carbonate matrix.
The process may further include providing a pre-treatment well for injecting the microbial stimulation fluid. The pre-treatment well may include a vertical well, a slanted well, a horizontal well or a combination thereof. The process may include terminating injection of the microbial stimulation fluid through the pre-treatment well and then operating the pre-treatment well for the hydrocarbon recovery. The pre-treatment well may be operated as a CSS
well for the hydrocarbon recovery and/or as part of a SAGD well pair including a SAGD injection well overlying a SAGD production well.
The process may include providing the pre-treatment well as an infill well in a bypassed hydrocarbon bearing zone in between two steam chambers of previously operating thermal hydrocarbon recovery wells, and operating the pre-treatment well to pre-treat the bypassed hydrocarbon bearing zone.
The process may also include providing at least a first and a second of the pre-treatment well. The first pre-treatment well and the second pre-treatment well may be configured and located so as to be separated by an interwell region. The process may also include injecting the microbial stimulation fluid through the first pre-treatment well and the second pre-treatment well to form respective first and second pre-treated zones having reduced permeability and porosity; and connecting the first and second pre-treated zones to form a common pre-treatment zone having increased porosity and permeability. The first and second pre-treatment wells may be operated as CSS wells for the hydrocarbon recovery. The first and second pre-treatment wells may alternatively be operated as a SAGD well pair for the hydrocarbon recovery.
Injecting the microbial stimulation fluid may be performed prior to any operation of the hydrocarbon recovery.
The process may include operating the pre-treatment well as part of a mature or wind-down operation of the hydrocarbon recovery.

The byproduct may promote development of water-wet carbonate particles in the region.
The process may further include soaking the region of the carbonate reservoir with the injected microbial stimulation fluid for a soaking period.
The soaking period may be between about 1 month and about 12 months.
There is also provided a process for recovery of heavy hydrocarbons from a carbonate reservoir, including injecting a microbial stimulation fluid into a region of the carbonate reservoir; providing a reservoir temperature in the region that allows microbial conversion of the microbial stimulation fluid into a byproduct to dissolve carbonates, wherein dissolution of the carbonates increases permeability and porosity in the region; soaking the region of the carbonate reservoir with the injected microbial stimulation fluid for a soaking period; and injecting a mobilizing fluid into the region to produce mobilized heavy hydrocarbons and recovering the mobilized heavy hydrocarbons from the carbonate reservoir The mobilizing fluid may include hot water, steam or solvent or a combination thereof.
The microbial stimulation fluid may include a mixture of CO2 and H2 and the microbial conversion includes acetogenesis by the Wood-Ljungdahl pathway for producing acetic bioacid as the byproduct.
There is further provided a process for recovery heavy hydrocarbons from a carbonate reservoir, including identifying a hydrocarbon bearing region that includes a microbial culture and is positioned between a first hydrocarbon depleted zone and a second hydrocarbon depleted zone; injecting a microbial stimulation fluid into the hydrocarbon bearing region, wherein the region is at a reservoir temperature allowing a microbial metabolic pathway to convert the microbial stimulation fluid into a byproduct to promote dissolution of carbonate compounds in the hydrocarbon bearing region, wherein dissolution of the carbonate compounds increase porosity and permeability in the region forming a pre-treated zone in the region; and operating an infill well in the pre-treated zone to recover heavy hydrocarbons from the region.

The hydrocarbons may have been recovered from the first hydrocarbon depleted zone and the second hydrocarbon depleted zone using a hydrocarbon recovery system including SAGD and the first and second hydrocarbon depleted zones are first and second steam chambers respectively. The hydrocarbons may have been recovered from the first hydrocarbon depleted zone and the second hydrocarbon depleted zone using a hydrocarbon recovery system including CSS.
The process may include heating the hydrocarbon bearing region to the reservoir temperature at least partially with heat from the hydrocarbon recovery system.
There is also provided a process for recovery heavy hydrocarbons from a carbonate reservoir, including identifying a hydrocarbon bearing region adjoining a heated hydrocarbon depleted zone from which heavy hydrocarbons have been produced using a thermal recovery well, wherein the hydrocarbon bearing region includes a microbial culture; injecting a microbial stimulation fluid into the hydrocarbon bearing region, wherein the region is at a reservoir temperature allowing a microbial metabolic pathway to convert the microbial stimulation fluid into a byproduct to promote dissolution of carbonate compounds in the outer hydrocarbon bearing region, thereby forming a pre-treated zone in the hydrocarbon bearing region having increased porosity and permeability; and operating the thermal recovery well to heat and produce heavy hydrocarbons from the pre-treated zone.
The process may include reducing heat in the heated hydrocarbon depleted zone to achieve the reservoir temperature in the outer hydrocarbon bearing region. The process may include injecting the microbial stimulation fluid through the thermal recovery well. The thermal recovery well may be part of a CSS or SAGD heavy hydrocarbon recovery operation.
There is also provided a system for pre-treating a carbonate reservoir that includes heavy hydrocarbons in preparation for hydrocarbon recovery. The system includes a pre-treatment well for injecting a microbial stimulation fluid into a region of the carbonate reservoir that includes a microbial culture;
and a heating arrangement for heating the region to a reservoir temperature allowing a microbial metabolic pathway to convert the microbial stimulation fluid into a byproduct to promote dissolution of carbonate compounds in the region, wherein dissolution of the carbonate compounds increases porosity and permeability of the region.
The pre-treatment well may include an injection section configured for injecting a gaseous fluid as the microbial stimulation fluid.
The heating arrangement may include an aboveground heating device for heating the microbial stimulation fluid prior to injection into the region, an underground heating device, and/or a thermal hydrocarbon recovery well adjacent to the region.
The microbial stimulation fluid may be a gas and the system may further include an aboveground compressor for compressing the gas for injection.
The system may also include a temperature measurement device for measuring the temperature of the region.
It should also be noted that implementations and aspects of the processes and systems described herein may be combined with the processes and system as described above.
BRIEF DESCRIPTION OF THE DRAWINGS
Fig 1 is a side view schematic of a SAGD well pair.
Figs 2a-2d are side view schematics of a vertical well.
Fig 3 is a top view schematic of a SAGD well pad and well pairs.
Fig 4 is a front view schematic of a SAGD well pair.
Fig 5 is a front view schematic of two SAGD well pairs and a horizontal infill well.

Fig 6 is a front view schematic of two SAGD well pairs and a vertical infill well.
Figs 7a-7c are front view schematics of two SAGD well pairs.
Figs 8a and 8b are top view schematics of a well pattern including multiple wells.
Figs 9a-9d are front view schematics of a SAGD well pair showing a wind-down operation.
Fig 10 is a process block flow diagram.
DETAILED DESCRIPTION
10 Systems and techniques are described that leverage indigenous microbial communities present in a carbonate reservoir for biological conversion of an injected stimulation fluid into organic bioacid compounds sufficient for pre-treating the carbonate reservoir to enhance a subsequent in situ heavy hydrocarbon recovery operation.
"Carbonate reservoirs" should be understood as reservoirs including heavy hydrocarbons and regions that are predominantly composed of sedimentary rocks deposited in a marine environment and include carbonate minerals, such as calcium carbonate. The carbonate minerals may include different forms of carbonates such as aragonite, calcite, magnesium calcite, dolomite, and so on. The carbonate reservoir also includes fragments of marine components, such as marine organisms, skeletons, coral, algae, and the like.
Carbonate reservoirs are also naturally fractured formations with heterogeneous porosity and permeability distributions. The carbonate reservoirs are also characterized as including regions with lower permeability and porosity compared to oil sands reservoirs. Such regions have permeabilities low enough such that the microbial metabolism of the injected microbial stimulation fluid increases the permeability and porosity by dissolution of carbonates, while being high enough to allow injection and permeation of the microbial stimulation fluid into the regions. The low permeability regions of the carbonate reservoir may have an initial reservoir permeability of approximately 1 mD - 200 mD, or approximately 10 mD - 100 mD, for example. The porosities may range between 7% and 20%, for example. The carbonate reservoir may contain bitumen and be composed of sedimentary dolomite and limestone, such as reservoirs located in the Western Canadian Sedimentary Basin (WCSB) in Alberta, Canada. The carbonate reservoirs may be located in the bitumen bearing carbonate formations of the Grosmont, the Nisku, the Debolt and the Shundra, for example.
"Heavy hydrocarbons" in the carbonate reservoir should be understood as having a high viscosity and an American Petroleum Institute (API) gravity below 20 at initial reservoir conditions. The heavy hydrocarbons may be mobile or immobile at initial reservoirs conditions and may have different characteristics depending on the given reservoir or location within a given reservoir. Heavy hydrocarbons should be understood to include what are generally known as heavy oil, extra-heavy oil and bitumen. Based on API
gravity, heavy oil has an API gravity between 10 and 20, while extra-heavy oil and bitumen have an API less than 10. For example, bitumen occurring in the Grosmont formation generally has an API gravity between 5 and 9.
Systems and techniques are described for pre-treating a carbonate reservoir that includes heavy hydrocarbons prior to hydrocarbon recovery. A microbial stimulation fluid is injected into a region of the carbonate reservoir, where the region is at a temperature sufficient for metabolic activity of a microbial community for production of a byproduct that promotes dissolution of carbonates present in the region. Dissolving carbonates in the region increases the permeability and porosity of the region, thereby facilitating subsequent hydrocarbon recovery from the carbonate reservoir. The porosity of the region increases with carbonate dissolution and permeability also increases in general, though there may be certain micro-regions within the overall region where only porosity is increased.
The temperature of the region is high enough such that the microbial cultures are biologically active and metabolize the conversion of the microbial stimulation fluid into the byproduct, yet not so high as to detrimentally affect the microbial cultures present in the carbonate reservoir. Excessive temperatures can inhibit the desired metabolic pathway and byproduct production or even destroy the microbial culture. At insufficiently low temperatures, such as initial reservoir temperatures that are approximately C, microbial cultures are either dormant or substantially inactive and produce little to no effective byproducts enabling carbonate dissolution. If the region is not at the desired temperature, the region can be heated to the desired temperature. For example, the microbial stimulation fluid can be 10 heated to a temperature such that when injected into the region, the region is warmed to an adequate temperature. The temperature of the region allows conversion of the microbial stimulation fluid by the microbial metabolic pathway into a byproduct that promotes dissolution of carbonates. The temperature enabling this microbial conversion therefore depends on the given microbial metabolic pathway.
The region of the carbonate reservoir may be identified or selected in accordance with the presence of an indigenous microbial culture. The indigenous microbial culture, which may be identified by sampling techniques, should be capable of metabolizing the injected microbial stimulation fluid into a carbonate dissolving byproduct. The microbial stimulation fluid is selected to enable the microbial cultures present in the carbonate reservoir to consume one or more components of the fluid and thereby produce the byproduct that promotes dissolution of carbonates present in the region. The microbial stimulation fluid may include components in relative proportions according to the metabolic pathway for providing carbon and energy sources for producing the desired byproduct of the particular microbial culture.
The region of the carbonate reservoir may be identified or selected in accordance with the porosity and permeability of the region. The porosity and permeability may be identified by estimation, modeling, sampling or seismic response techniques, in order to identify a target zone for injection and pre-treatment. Such a target zone may have permeabilities that are high enough to facilitate gas injection while being low enough to be increased due to carbonate dissolution to thereby improve the hydrocarbon recovery. Sampling or seismic data may be used to model the carbonate reservoir to determine one or more target zones for pre-treatment, depending on initial porosity and permeability, the indigenous microbial cultures, and the geological characteristics of the reservoir, such as the distribution of fractures, vugs, carbonate rock type and densities and/or bitumen.
In some implementations, the microbial culture in the region of the carbonate reservoir may include an organic bioacid-producing microbial culture, for instance acetogens that metabolize H2 and CO2 into acetic bioacid according to the following reaction (I):
4H2 + 2CO2 CH3COOH + 2H20 (I) Injection of the microbial stimulation fluid including CO2 and H2 gas into the target region of the carbonate reservoir allows the gas to permeate the carbonate matrix in the region and provide a carbon substrate and a hydrogen energy source for the acetogens. The microbial stimulation fluid may include H2 and CO2 in relative proportions according to the metabolic pathway for producing the acetic bioacid for example in order to facilitate the metabolic reaction (I).
The bacterial pathway for acetogenesis may be the so-called Wood-Ljungdahl pathway. The acetogens may be those known as Clostridium acetium, clostridium in the thermoanaerobacteriaceae family such as Moorella thermoacetica, and Acetobacterium woodii. Acetobacterium woodii has notably been shown to grow on H2 and CO2 and produce acetic acid.
Various acetogens can also use other carbon sources and electron donors and acceptors. It should thus be understood that the microbial cultures in the carbonate reservoirs may also be able to metabolize compounds other than H2 and CO2 and such additional compounds may be included in the microbial stimulation fluid or present in the carbonate reservoir itself.
The acetogens enable the production of acetic bioacid that, in turn, may facilitate the dissolution of carbonates present in the carbonate reservoir according to the following reaction (II):

CaCO3 + CH300H 4 Ca2+ + CH3000- + HCO3- (II) The temperature of the region for acetogenesis may be provided in a range promoting conversion of H2 and CO2 gas into acetic bio-acid by the Wood-Ljungda hl pathway. Such an acetogenesis temperature may be between 15 C and 80 C, between 20 C and 70 C, between 30 C and 60 C, or between 45 C and 55 C, for example. When the heavy hydrocarbons are bitumen, the temperature may be sufficiently high to achieve viscosity reduction to have slight molasses-like mobility of the bitumen, which is typically considered to be above 45 C. Temperatures about this threshold may enhance injectivity, microbial growth and distribution in the region of the reservoir.
Optional implementations of the processes and systems are described below in relation to injection strategies, fluid compositions, operating conditions and well configurations.
In some implementations, the microbial stimulation fluid is injected into the region at a temperature in order to heat the region of the carbonate reservoir to the desired temperature. The fluid temperature should be high enough to heat the region to the desired temperature, yet not so high such that the fluid front overheats the region as it passes into the region to detrimentally affect the microbial activity. The region may also be heated by a source other than the microbial stimulation fluid before or during fluid injection. Heating may be accomplished by injection of a separate heating fluid or by a downhole heater device. Heating may also be accomplished by a previous or concurrent hydrocarbon recovery operation adjacent to the region. The region may be located beside or in between a thermal hydrocarbon recovery operation, such as SAGD or CSS, from which heat is transmitted into the region to heat it to the desired temperature. The region may also be heated using a combination of the above methods.
In addition, at very high temperatures, such as those in steam injection thermal recovery operations in the range of 200 C, acetogens can be destroyed. However, some acetogens have been found to have highly resistive spores up to 120 C-140 C. Furthermore, some acetogenic bacteria can survive at low temperatures of about 1 C. The region may therefore be heated or cooled in order to achieve a temperature to favour microbial metabolism of the injected stimulation fluid.
In some implementations, the temperature of the region may provided to enable conditions favouring fluid injectivity, microbial metabolic conversion of the fluid into byproducts, and dissolution of carbonates by the byproducts, thereby increasing permeability and porosity of the carbonate formation. For instance, the temperature of the region may be provided so as to increase 10 injectivity in the target region, thereby facilitating injection of the microbial stimulation fluid to access the microbial culture. The temperature may also be provided to improve reaction conditions not only for the microbial metabolic reactions, such as acetogenesis, but also for carbonate dissolution. By favoring both the microbial production and the carbonate dissolution, the increase in porosity and permeability may be accelerated and the overall pre-treatment may be enhanced.
Therefore, the temperature may be optimized or adjusted according to such temperature dependent variables to maximize permeability and porosity. The temperature may be optimized or adjusted to maximize water-wet condition of the carbonate matrix in the region. The temperature may be optimized or adjusted to maximize the subsequent overall hydrocarbon recovery.
Referring now to Fig 1, the process for pre-treating the carbonate reservoir including heavy hydrocarbons, such as bitumen, for hydrocarbon recovery includes providing a well 10 in a region of the carbonate reservoir 12. The well 10 may be provided for the eventual purpose of in situ bitumen recovery and is utilized for pre-treatment prior to commencing the in situ recovery operation.
There is often a timeframe of several months after completion of an in situ recovery well before steam or other mobilizing fluid is supplied to it. During this window, the in situ recovery well can be operated as a pre-treatment well 10.

In some implementations, the pre-treatment well 10 is provided as a dedicated in situ recovery well and operated initially as a pre-treatment well 10. Figs 1, 3, 4, 7a-7c and 9 illustrate the scenario where the pre-treatment well 10 is an injection well of a SAGD well pair 14, which also includes an underlying production well 16. In Fig 1, only the eventual SAGD injection well is used a pre-treatment well 10 and the production well is not operated. It should be understood that there may be multiple pre-treatment wells arranged in a variety of configurations, which may correspond to the subsequent in situ recovery well pattern. For example, Figs 7a-7c illustrate the optional aspect where both wells of the SAGD well pair, including the production well 16, are initially used as pre-treatment wells for gas injection.
Figs 8a and 8b illustrate the scenario of a multi-well pattern of vertical wells for subsequent steam flooding, CSS or FCSS and the wells are used as pre-treatment wells 10.
Referring now to Figs 1 and 2a-2d, the process includes injecting the microbial stimulation fluid F that may include CO2 through the pre-treatment well 10 into the region of the carbonate reservoir 12 that includes a microbial culture. Injection of the fluid F provides a substrate to the microbial culture in order to enable the pre-treatment as will be further described below.
As illustrated in Figs 2a-2d, the injected fluid F may penetrate the carbonate reservoir 12 to form a gas rich zone 18. The gas rich zone 18 may expand outwardly from the pre-treatment well 10 in accordance with the injection pressure and the geological characteristics of the carbonate formation, including its permeability, porosity and fracture properties. The gas rich zone may have a regular or irregular shape depending on the characteristics of the reservoir and the injection locations.
The microbial stimulation fluid comes into contact with the microbial culture thereby providing a substrate and enabling the culture to metabolize at least one component in the fluid to product a byproduct, such as organic bioacid, to promote dissolution of carbonates present in the carbonate reservoir. This carbonate dissolution improves the subsequent in situ hydrocarbon recovery.
The organic bioacid therefore dissolves carbonates and forms a microbially pre-treated zone 20. An example of the progressive advancement of the gas rich zone 18 and the microbially pre-treated zone 20 is illustrated in Figs 2a-2d in connection with a single vertical well 10.
The microbial stimulation fluid may be a gas and may be referred to as the "gas" hereafter in most implementations of the pre-treatment process.
However, in some cases the fluid may be a gas-liquid mixture depending on its particular constituents. Providing the microbial stimulation fluid as a gas facilitates injectivity into the carbonate reservoir and may be appropriate for certain microbial metabolic pathways. The microbial stimulation fluid may include a co-injected mixture of CO2 and H2, though it may be an alternating injection of H2 and CO2 or injection of the two gases via two distinct pre-treatment wells into the same target zone. The microbial stimulation fluid may include water or microbial nutrients as well. The microbial stimulation fluid may have a composition to provide excess substrate to promote a metabolic pathway for bioacid production, as well as energy sources and nutrients that may be appropriate for the given microbial culture.
As noted above and illustrated in the figures, the pre-treatment well 10 may be horizontal or vertical, which is often determined on the in situ recovery technique for which it was provided. Such in situ recovery wells may be for processes such as SAGD, VAPEX, CSS, FOSS, flooding with steam, water or solvents, solvent assisted SAGD, other solvent assisted processes, in situ combustion processes, and so on, some of which are illustrated in the Figs.
Referring particularly to Figs 5 and 6, in some implementations, the pre-treatment well 10 may be a SAGD infill well which is provided in a hydrocarbon bearing region 22 defined in between two adjacent SAGD steam chambers, which may more generally be referred to as two hydrocarbon depleted zones. The steam chambers may be joined together as illustrated or may not yet have coalesced when the pre-treatment process is performed.
The hydrocarbon bearing region 22 may also be referred to as an unrecovered hydrocarbon bearing zone 22 in between two injection-production well pairs 14a, 14b of the SAGD hydrocarbon recovery setup. The infill wells may be horizontal or vertical wells, as illustrated in the two Figs.

The pre-treatment well 10 may be operated in order to pre-treat the unrecovered hydrocarbon bearing zone 22 prior to producing hydrocarbons from the infill well or injecting steam, hot water, solvent or other mobilizing fluids into the infill well. Since initiation or full operation of the infill well may be delayed due to economic or technical reasons, depending on the performance of the SAGD well pairs, the pre-treatment process may be conducted during such a delay.
Using a SAGD infill well as a pre-treatment well 10 may have some particular advantages. For instance, at least part of the unrecovered hydrocarbon bearing zone 22 contains heat that has conducted from the two SAGD steam chambers 24. While the steam chambers of the SAGD operation are too hot for microbial activity, the temperature of the bypassed zone 22, especially proximate the infill well, would not attain levels that would be detrimental to the microbial culture, but would be in a range that would encourage microbial metabolism of the injected substrate. The unrecovered zone 22 is thus pre-heated by the in situ recovery process, which further encourages the microbial pre-treatment of that zone to facilitate steam injection and/or hydrocarbon production from that zone. After pre-treatment, the infill well may be operated as a production well, an injection well, or a combination thereof 70 as in the case of CSS, for example.
In this regard, depending on the particular in situ recovery setup, the region in which the pre-treatment well 10 is provided may have been prepared to encourage the microbial pre-treatment process. When the pre-treatment well 10 is a step-out well of an existing well pattern (as illustrated in Fig 3) or an infill well (as illustrated in Figs 5 and 6), the region of the pre-treatment well may be pre-heated by the adjacent pre-existing in situ recovery operation.
Referring now to Figs 4 and 7a-7c, in some implementations, the pre-treatment process is conducted in connection with a SAGD well pair in order to pre-treat at least an inter-well region 23 in between the injection well and 30 the production well. Pre-treating the inter-well region 23 can facilitate accelerated startup of the SAGD well pair by establishing increased permeability and porosity in that region, and thus facilitating fluid communication between the injection well and the production well during startup. When a SAGD well pair undergoes startup, steam or solvent or another mobilizing fluid is injected into at least one of the wells, thereby mobilizing the surrounding area until fluid communication is established between the two wells. Fluid communication between injection and production wells is important for the functioning of the SAGD process.
Accelerating or providing more uniform fluid communication between the wells in the startup phase can speed up or improve the in situ recovery operation. In such a SAGD startup scenario, the injection well may be used for pre-treatment injection and the production well may be operated under a pressure sink or otherwise operated to encourage the gas to quickly permeate the inter-well region. In other in situ recovery arrangements, two adjacent wells may be similarly operated under injection and sink conditions to promote gas permeation in a certain direction or in a certain region.
In some implementations, the pre-treatment process facilitates establishing subsequent fluid communication between two proximate in situ recovery wells, such as between an injection-production SAGD well pair, two SAGD
injection wells, adjacent CSS wells, or other wells in a pattern where fluid communication may be desirable. The pre-treatment process may therefore be operated by injecting the microbial stimulation fluid through at least two wells until the microbially pre-treated zone 20 spans a region joining the at least two wells.
Referring to Fig 4, the target zone may be the inter-well region 23 and the pre-treatment may be operated until the microbially pre-treated zone 20 extends the entire height of the inter-well region 23. Both injection and production wells of the SAGD well pair may be used to obtain these microbially pre-treated zones. The pre-treatment process may be operated for a sufficient time and with sufficient gas injection such that microbially pre-treated zones 20 extending from the two wells join, establishing a combined pre-treated zone.
Referring to Figs 5 and 6, the target zone may be the region between the pre-treatment well 10 and the steam chambers 24, such that microbially pre-treated zone 20 extends through the bypassed region 22 and at least partially reaches a location proximate one or both of the steam chambers 24, that is until the point where microbial activity is prohibited by the high temperatures of the steam chambers.
Referring to Figs 7a-7c, the target zone may be a region in between two adjacent SAGD well pairs. The pre-treatment process may be operated for a sufficient time and with sufficient gas injection such that the microbially pre-treated zones 20 extending from the adjacent well pairs join as illustrated in Fig 7c, establishing a combined pre-treated zone.
10 In some implementations, the composition and the injection of the microbial stimulation fluid may be provided such that the target region of the carbonate reservoir is at conditions favoring a certain metabolic pathway or a certain microbial culture.
The microbial stimulation fluid may be provided such that the region has chemical and temperature conditions limiting or preventing methanogenesis and promoting acetogenesis, for instance by providing a pH value above about 5. In addition, providing an excess of a certain substrate may promote acetogens outcompeting other microbe that may be present. The composition of the fluid and injection rate of the fluid may be controlled, adjusted or 10 provided to achieve such reservoir conditions. In addition, the pH of the pre-treatment region may also be provided for shifting the equilibrium of the system to encourage dissolution of the carbonates.
In some implementations, the microbial stimulation fluid includes a carbon substrate and an energy source and may be provided in the gas phase. The carbon source may include CO2 and the energy source may include H2. The microbial stimulation fluid may include non-condensable gases, such as CO2 and H2, to avoid condensation of the gaseous fluid after injection which could reduce the ability of the fluid to permeate the region of the carbonate reservoir. It should nevertheless be noted that the microbial stimulation fluid may include an amount of condensable gas such as some solvents that would not detrimentally affect the microbes and/or of a fluid such as water.
In some scenarios, hot water may be added to the other components of the microbial stimulation fluid to provide heat for heating the carbonate reservoir.
Hot water may also be used to provide a medium to promote dissolution of the carbonates in combination with the microbial byproduct such as bioacid.
In some implementations, the microbial stimulation fluid is provided to the region in a relatively constant manner. For example, the fluid may be provided at a constant composition, temperature and injection flow rate. It is also possible to modify the injection of the microbial stimulation fluid, as a step change or gradually. For example, the fluid may have initial conditions for promoting bioacid production and, once sufficient bioacid has accumulated in the region, the fluid injection may be modified for promoting carbonate dissolution. In one scenario, the initial fluid composition may include amounts of CO2 and H2 promoting rapid production of acetic bioacid, and the fluid may be altered to include an amount of an additional compound enabling a temperature and/or condensate to form to increase the dissolution of carbonates. For instance, condensate may form in the region and combine with the acetic bioacid or product ions of reaction (II) to produce an aqueous solution. In another scenario, the injected microbial stimulation fluid may be heated at a later stage of the pre-treatment operation to accelerate dissolution of carbonates. The microbial stimulation fluid may be modified in accordance with estimates or measurements regarding the progression of the pre-treatment process.
In some implementations, the process further includes a preliminary step of identifying favorable target zones in the carbonate reservoir which contain the indigenous microbial culture prior to injecting the microbial stimulation fluid into the target zones. This identification step may be done using core sampling techniques, seismic prediction methods, geological predictions, and so on. The pre-treatment process may be initiated in the favorable target zones, which may then spread to other reservoir locations. The target zones may also be selected in accordance with low permeability and porosity to be improved and/or bitumen type and content that may be favorable for providing nutrient supply to the microbial culture. For example, the target zones may be chosen such that they contain the indigenous microbial culture and bitumen nutrient characteristics such that the injection of CO2 and H2 containing gas will produce sufficient bioacid to dissolve carbonates and reduce the permeability of that target zone prior to the availability of steam for the in situ hydrocarbon recovery process coming on line.
It is noted that the highly viscous bitumen in the Grosmont carbonate formation is the residue from extensive in situ biodegradation by active microbial communities. Carbonate reservoirs including bitumen have regions with indigenous microorganisms. It has been observed that mined oil sands and SAGD cores have relatively few thermophilic microorganisms (also called thermophiles), which is in agreement with the fact that the temperature in these environments being relatively low and constant (10 C). However, it has also been observed that oil sands outcrops harbor a relatively large fraction of thermophiles, suggesting that microbial activity is favored at the higher temperatures of the range experienced on outcrop slopes which can reach up to 60 C, likely due, at least partially, to the bitumen's lower viscosity at 60 C.
Bitumen typically begins to achieve a molasses-like mobility at approximately 45 C and becomes increasingly mobile above such temperature. Microbial activity in subsurface oil sands and heavy hydrocarbon carbonate reservoirs may thus be inhibited by the relatively low initial temperatures.
In some implementations, the pre-treatment process is targeted in one or more low permeability and porosity regions of the carbonate reservoir. The region may be an unkarsted dense limestone region. Karst is limestone in which erosion and diagenesis have produced fissures, tunnels and caverns, and can therefore have higher permeabilities up to 5,000 mD, while unkarsted regions have a dense limestone matrix with a low permeability in the range of approximately 100 mD. Regions having a dense limestone matrix with bitumen present in the matrix may be targeted to pre-treat such regions to provide sufficient permeability and porosity to enable hydrocarbon recovery operations to recovery the bitumen in the matrix.
In some implementations, the carbonate reservoir includes dense limestone regions and karsted regions. The karsted regions may include "vugs", which are cavities or fractures containing bitumen. The pre-treatment process may be performed so as to increase the porosity and permeability in the dense limestone regions of the carbonate reservoir. The injection and carbonate dissolution may be performed until a pre-treated zone expands to reach one or more of the karsted regions, so as to promote fluid communication of subsequently injected mobilizing fluid to access the bitumen in the vugs and/or promote production of mobilized heavy hydrocarbons from the vugs and matrix of the carbonate reservoir.
In some implementations, the pre-treatment process may also be performed such that the bioacid production is sufficient to at least partially reverse the wettability of some of the carbonate rock matrix in the reservoir, depending on the in situ recovery technique to be used to recover the hydrocarbons and the initial wettability characteristics of the reservoir. Reversing wettability may be advantageous when using an in situ process using steam injection, such as CSS or SAGD, which have better performance with water-wet matrices.
In some implementations, the injection of the microbial stimulation fluid is performed at a pressure below fracture pressure of the carbonate reservoir and sufficient to enable permeation of the gas into the target zone of the reservoir. The pressure may be provided in order that the injected gas permeates the target zone of the reservoir where subsequent in situ recovery 10 will occur. The pressure may be approximately the reservoir pressure.
In some implementations, the pre-treatment process may be conducted during a mature or wind-down stage of the in situ recovery operation instead of at a preliminary stage prior to initiation of the in situ recovery operation.
Figs 9a-9d illustrate a scenario where the pre-treatment process is conducted using a well that had been previously operated as an in situ recovery well.
More particularly, Fig 9a illustrates a SAGD well pair 14 which has been operating for a sufficient time that a steam chamber 24 has formed. The steam chamber 24 may be generally considered a heated hydrocarbon depleted zone. The illustrated steam chamber 24 has been well established;
30 however, it should be understood that sometimes the steam chamber does not evolve in such a regular shape and may be less developed or less uniform. Prior to initiating the pre-treatment injection of microbial stimulation fluid, the in situ operation may be scaled back or turned down in order to decrease the temperature in the target zone, since the high temperatures may reduce, inhibit or eliminate microbial activity in the zone. In this example, the target zone is an outer hydrocarbon bearing region adjoining the heated hydrocarbon depleted zone, such as the steam chamber. Once the reservoir is cooled to the desired temperature, the pre-treatment well may be initiated with microbial stimulation fluid injection, as illustrated in Fig 9b.
The injected gas permeates the reservoir and into the target zone, providing a substrate for microbial production of carbonate dissolving byproduct that, in turn, allows dissolution of carbonates. The gas permeation zone 18 and the microbially pre-treated zone 20 are illustrated in Figs 9c and 9d. The pre-treatment process therefore prepares the target zone for the re-initiation of the in situ recovery operation. This scenario is possible provided the temperature in the outer hydrocarbon bearing region was not too high so as to permanently destroy or impair microbial activity.
In this regard, it is noted that at the very high temperatures as those present in the steaming zones in SAGD and CSS, acetogenic bacteria can die.
However, some variants of acetogens have been found to have highly resistive spores ranging up to 120-140 C. When associated with a previously operated thermal in situ recovery operation, the pre-treatment process may be alternated with the thermal recovery operation in order to access resistant and micro bially treatable zones of the carbonate reservoir.
It should also be noted that the pre-treatment process may be used in a carbonate reservoir in cases where initial start-up or ramp-up of the in situ recovery operation encountered difficulty and could benefit from stimulation of relevant target zones of the reservoir. In situ recovery wells encountering difficulty, for example due to low permeability and porosity in important zones of the reservoir, may be converted into pre-treatment wells.
In some implementations, the pre-treatment is conducted prior to any in situ recovery operation. Thus, an overall process is provided for recovery of heavy hydrocarbons from a carbonate reservoir, including pre-treating the carbonate reservoir by injecting a microbial stimulation fluid to produce a microbially pre-treated zone including dissolved carbonates and having increased permeability and porosity; and recovering the heavy hydrocarbons by injecting a mobilizing fluid into the microbially pre-treated zone to produce mobilized heavy hydrocarbons and producing the mobilized heavy hydrocarbons from the carbonate reservoir.
In some implementations, the progression of carbonate dissolution may be measured or investigated during the pre-treatment process. For example, reservoir or fluid injection characteristics may be monitored. The reservoir 10 may be monitored using sensors on the pre-treatment well or a separate measurement well, to determine temperature or other properties of the well.
The fluid injection may be monitored by measuring injection pressures, flow rates, and so on. In some scenarios, the injection may be modified to investigate an aspect of the process. For example, the pre-treatment well may be temporarily converted into a production well to try to produce fluids (temperature and mobility permitting) from the region of the reservoir, thereby assessing the producability of the region. The pre-treatment well may then be converted back to injection mode and adjusted in accordance with the production mode characteristics or the properties of the produced fluids.
20 Referring to Figs 1-9d, the system for pre-treating a carbonate reservoir including heavy hydrocarbons in preparation for hydrocarbon recovery, includes a pre-treatment well 10 for injecting a microbial stimulation fluid into a region of the carbonate reservoir including a microbial culture. The system also includes a heating arrangement for heating the region to a reservoir temperature allowing a microbial metabolic pathway to convert the microbial stimulation fluid into a byproduct to promote dissolution of carbonate compounds in the region and thereby increasing porosity and permeability of the region.
Referring to Fig 1, in some implementations, the heating arrangement includes an aboveground heating device 26 for heating the microbial stimulation fluid prior to injection into the region.

The heating arrangement may include an underground heating device, such as an electrical heater. The heating arrangement may include a thermal hydrocarbon recovery well adjacent to the region, as per scenarios illustrated in Figs 3, 5, 6, 8 and 9, for example.
Fig 1 also illustrates that the system may include an aboveground compressor for compressing a gaseous microbial stimulation fluid for injection. Various aboveground heater and compressor configurations may be provided for other well patterns and in situ recovery operations, in order to inject a heated microbial stimulation gas into the region of the carbonate reservoir.
The system may also include a temperature measurement device for measuring the temperature of the region.
In some implementations, the microbial stimulation fluid may include CO2, which may be derived from an in situ hydrocarbon operation, a bitumen mining operation, a bitumen extraction operation, a hydrocarbon upgrading operation, a power production operation or a combination thereof. The process may also enable at least some CO2 sequestration by injecting CO2 into the carbonate reservoir.
In an example of a microbial culture present in heavy hydrocarbon bearing formations, incubation of field waters from several oil reservoirs with H2 and CO2 has shown high activity of acetogens (4H2 + 2CO2 CH3COOH +
2H20) with up to 90 mM of acetic bioacid being formed in 40 days of incubation at 23 C. Methanogenesis did not start until acetogenesis stopped at the low pH value of 5. Acetic bioacid formation proceeded even when a layer of heavy oil separated the gas mixture from the produced water, indicating the effective diffusion of H2 and CO2 through the intervening viscous hydrocarbon phase.
It should be understood that other variations, implementations and scenarios may also be used for the systems and processes described herein. For instance, in another implementation, a microbial culture may be injected into the carbonate reservoir before, during, after or in conjunction with the injection of the microbial stimulation fluid. The injected microbial culture may be the sole or predominant microbial culture enabling metabolic production of the byproduct allowing carbonate dissolution, or the injected microbial culture may be in addition and complementary to an indigenous microbial culture in the region of the reservoir. The injected microbial culture may be the same or different from an indigenous microbial culture that is present in the injection region. The injected microbial culture may be indigenous to another carbonate reservoir. The injected microbial culture may be a microbial culture that is not indigenous to carbonate reservoirs, but has a metabolic pathway that can convert the microbial injection fluid into a desired byproduct. For example, the culture may include acetogens that naturally occur in other media such as soils or various anaerobic environments, The injected microbial culture may be a naturally occurring microorganism or may be a modified or selectively evolved microorganism for effecting the desired metabolic production. The microbial culture may be modified or selected in order to metabolize certain compounds that are present in the carbonate reservoir, such as certain components of bitumen or other heavy hydrocarbons present in the reservoir. The injected microbial culture may have been modified or selected in order to have a temperature resistance in accordance with a desired or existing temperature of the reservoir. The injected microbial culture may be injected with the microbial stimulation fluid, alternatively through the same pre-treatment well as the microbial stimulation fluid, or through a different pre-treatment well or other reservoir inoculation technique. The injected microbial culture may be injected and provided in a certain amount or at a certain location of the carbonate reservoir so as to achieve a desired pre-treatment strategy, which may include production quantity or rate of the byproduct, level of porosity and/or permeability increase, and so on.

Claims

1. A process comprising:
injecting a microbial stimulation fluid into a region of a carbonate reservoir, wherein the region includes heavy hydrocarbons and a microbial culture;
temperature treating the region to a reservoir temperature that allows a microbial metabolic pathway of the microbial culture to convert the microbial stimulation fluid and generate a byproduct to promote dissolution of carbonate compounds in the region;
soaking the region for a soak period during which carbonate compounds dissolve and porosity of the region is increased; and following the soak period, recovering heavy hydrocarbons from the region of increased porosity.

2 The process of claim 1, wherein the microbial stimulation fluid includes CO2.

3. The process of claim 1 or 2, wherein the microbial stimulation fluid further includes H 2.

4. The process of any one of claims 1 to 3, further comprising.
preheating the microbial stimulation fluid to a heated temperature, thereby producing a preheated microbial stimulation fluid, before injection;
wherein temperature treating the region comprises heating the region with heat conducted from the preheated microbial stimulation fluid

5. The process of any one of claims 1 to 4, wherein recovering heavy hydrocarbons comprises:

subjecting the region to a SAGD recovery process.

6. The process of any one of claims 1 to 4, wherein recovering heavy hydrocarbons comprises.
subjecting the region to a CSS recovery process.

7. The method of any one of claims 1 to 6, further comprising:
identifying the microbial culture indigenous to the region of the carbonate reservoir; and selecting the microbial stimulation fluid based on the identification and such that the microbial metabolic pathway will convert the microbial stimulation fluid to generate the byproduct that promotes dissolution of carbonate compounds in the region.

8. A process for pre-treating a carbonate reservoir comprising heavy hydrocarbons in preparation for hydrocarbon recovery, comprising:
injecting a microbial stimulation fluid into a region of the carbonate reservoir wherein the region includes a microbial culture, wherein the region is at a reservoir temperature allowing a microbial metabolic pathway of the microbial culture to convert the microbial stimulation fluid into a byproduct to promote dissolution of carbonate compounds in the region; and wherein the dissolution of the carbonate compounds increases porosity and permeability of the region.

9. The process of claim 8, wherein the carbonate reservoir comprises a stratigraphical unit with sedimentary dolomite and limestone.

10. The process of claim 8 or 9, wherein the region of the carbonate reservoir comprises a dense limestone matrix and at least a portion of the heavy hydrocarbons are in the dense limestone matrix.

11. The process of any one of claims 8 to 10, wherein the region of the carbonate reservoir has a low permeability between 1 mD and 200 mD.

12. The process of claim 11, wherein the region of the carbonate reservoir has a low permeability between 1 mD and 10 mD.

13. The process of any one of claims 8 to 12, wherein the microbial stimulation fluid is gaseous.

14. The process of any one of claims 8 to 13, wherein the microbial stimulation fluid comprises CO2.

15. The process of claim 14, wherein the microbial stimulation fluid comprises H2.

16 The process of claim 15, comprising co-injecting a mixture comprising the CO2 and the H2 as the microbial stimulation fluid

17. The process of any one of claims 14 to 16, wherein the microbial metabolic pathway converts the CO2 into a bioacid as the byproduct.

18. The process of any one of claims 14 to 17, wherein the microbial culture comprises an acetogen and the metabolic pathway comprises the Wood-Ljungdahl pathway, thereby producing acetic bioacid as the byproduct.

19. The process of claim 18, wherein the microbial stimulation fluid comprises the H2 and the CO2 in a molar proportion in accordance with the Wood-Ljungdahl pathway for production of the acetic bioacid.

20. The process of any one of claims 14 to 19, wherein the microbial stimulation fluid further comprises water.

21. The process of any one of claims 14 to 20, wherein the CO2 is derived from an in situ hydrocarbon recovery operation, a bitumen mining operation, a bitumen extraction operation, a hydrocarbon upgrading operation, a power production operation, or a combination thereof.

22. The process of any one of claims 14 to 21, wherein at least part of the CO2 is sequestered in the carbonate reservoir.

23. The process of any one of claims 8 to 22, further comprising:
heating the region of the carbonate reservoir to the reservoir temperature by injecting the microbial stimulation fluid at a fluid temperature sufficient to heat the region without detrimentally affecting the microbial culture.

24. The process of claim 23, wherein the temperature of the microbial stimulation fluid is between 15°C and 80°C.

25. The process of claim 24, wherein the temperature of the microbial stimulation fluid is between 20°C and 60°C.

26. The process of any one of claims 8 to 25, further comprising.
heating the region of the carbonate reservoir by a separate heat source from the microbial stimulation fluid.

27. The process of claim 26, wherein heating of the region by a separate heat source comprises operating a thermal in situ recovery operation adjacent to the region, before or during the pre-treatment process.

28. The process of any one of claims 8 to 27, wherein the hydrocarbon recovery is selected from Steam Assisted Gravity Drainage (SAGD), Vapor Extraction Process (VAPEX), Cyclic Steam Stimulation (CSS), Fracture assisted Cyclic Steam Stimulation (FCSS), Flooding with steam, water or solvents, solvent assisted SAGD, solvent or surfactant assisted processes, in situ combustion processes, and combinations thereof.

29. The process of any one of claims 26 to 28, wherein.
heating of the region by a separate source comprises injecting a heating fluid into or adjacent to the region.

30. The process of any one of claims 26 to 29, wherein-heating of the region by a separate source comprises operating a heating device in or adjacent to the region.

31. The process of any one of claims 8 to 30, wherein the microbial stimulation fluid further comprises an additional microbial nutrient.

32. The process of any one of claims 8 to 31, wherein the microbial culture consists of an indigenous in situ microbial culture.

33. The process of any one of claims 8 to 32, further comprising identifying one or more target zones defining the region of the carbonate reservoir, wherein the target zones include the microbial culture and the microbial stimulation fluid is injected into the target zones.

34. The process of claim 33, wherein target zones are identified based on having a permeability of at most 100 mD.

35. The process of claim 33 or 34, wherein the target zones are identified based on comprising an oil-wet carbonate matrix.

36. The process of any one of claims 8 to 35, further comprising providing a pre-treatment well for injecting the microbial stimulation fluid.

37. The process of claim 36, wherein the pre-treatment well comprises a vertical well, a slanted well, a horizontal well or a combination thereof.

38. The process of claim 36 or 37, further comprising:

terminating injection of the microbial stimulation fluid through the pre-treatment well and then operating the pre-treatment well for the hydrocarbon recovery.

39. The process of claim 38, wherein the pre-treatment well is operated as a CSS well for the hydrocarbon recovery.

40. The process of claim 38, wherein the pre-treatment well is operated as part of a SAGD well pair comprising a SAGD injection well overlying a SAGD production well.

41. The process of claim 38, comprising;
providing the pre-treatment well as an infill well in a bypassed hydrocarbon bearing zone in between two steam chambers of previously operating thermal hydrocarbon recovery wells, and operating the pre-treatment well to pre-treat the bypassed hydrocarbon bearing zone.

42. The process of any one of claims 36 to 41, comprising providing at least a first and a second of the pre-treatment well.

43. The process of claim 42, wherein the first pre-treatment well and the second pre-treatment well are configured and located so as to be separated by an interwell region.

44. The process of claim 43, comprising injecting the microbial stimulation fluid through the first pre-treatment well and the second pre-treatment well to form respective first and second pre-treated zones having reduced permeability and porosity; and connecting the first and second pre-treated zones to form a common pre-treatment zone having increased porosity and permeability.

45. The process of claim 44, wherein the first and second pre-treatment wells are operated as CSS wells for the hydrocarbon recovery.

46. The process of claim 44, wherein the first and second pre-treatment wells are operated as a SAGD well pair for the hydrocarbon re covery.

47. The process of any one of claims 8 to 46, wherein the injecting of the microbial stimulation fluid is performed prior to any operation of the hydrocarbon recovery.

48. The process of any one of claims 8 to 47, comprising operating the pre-treatment well as part of a mature or wind-down operation of the hydrocarbon recovery.

49. The process of any one of claims 8 to 48, wherein the byproduct promotes development of water-wet carbonate particles in the region.

50. The process of any one of claims 8 to 49, further comprising:
soaking the region of the carbonate reservoir with the injected microbial stimulation fluid for a soaking period.

51. The process of claim 50, wherein the soaking period is between about 1 month and about 12 months.

52. A process for recovery of heavy hydrocarbons from a carbonate reservoir, comprising.
injecting a microbial stimulation fluid into a region of the carbonate reservoir, wherein the region includes a microbial culture;
providing a reservoir temperature in the region that allows the microbial culture perform microbial conversion of the microbial stimulation fluid into a byproduct to dissolve carbonates, wherein dissolution of the carbonates increases permeability and porosity in the region;
soaking the region of the carbonate reservoir with the injected microbial stimulation fluid for a soaking period; and injecting a mobilizing fluid into the region to produce mobilized heavy hydrocarbons and recovering the mobilized heavy hydrocarbons from the carbonate reservoir.

53. The process of claim 52, wherein the mobilizing fluid comprises hot water, steam or solvent or a combination thereof.

54. The process of claim 52 or 53, wherein the microbial stimulation fluid comprises a mixture of CO2 and H2 and the microbial conversion comprises acetogenesis by the Wood-Ljungdahi pathway for producing acetic bioacid as the byproduct.

55. A process for recovery heavy hydrocarbons from a carbonate reservoir, comprising:
identifying a hydrocarbon bearing region that includes a microbial culture and is positioned between a first hydrocarbon depleted zone and a second hydrocarbon depleted zone;
injecting a microbial stimulation fluid into the hydrocarbon bearing region, wherein the region is at a reservoir temperature allowing a microbial metabolic pathway of the microbial culture to convert the microbial stimulation fluid into a byproduct to promote dissolution of carbonate compounds in the hydrocarbon bearing region, wherein dissolution of the carbonate compounds increase porosity and permeability in the region forming a pre-treated zone in the region; and operating an infill well in the pre-treated zone to recover heavy hydrocarbons from the region.

56. The process of claim 55, wherein hydrocarbons were recovered from the first hydrocarbon depleted zone and the second hydrocarbon depleted zone using a hydrocarbon recovery system comprising SAGD and the first and second hydrocarbon depleted zones are first and second steam chambers respectively.

57. The process of claim 55, wherein hydrocarbons were recovered from the first hydrocarbon depleted zone and the second hydrocarbon depleted zone using a hydrocarbon recovery system comprising CSS.

58. The process of any one of claims 55 to 57, comprising heating the hydrocarbon bearing region to the reservoir temperature at least partially with heat from the hydrocarbon recovery system.

59. A process for recovery heavy hydrocarbons from a carbonate reservoir, comprising identifying a hydrocarbon bearing region adjoining a heated hydrocarbon depleted zone from which heavy hydrocarbons have been produced using a thermal recovery well, wherein the hydrocarbon bearing region includes a microbial culture;
injecting a microbial stimulation fluid into the hydrocarbon bearing region, wherein the region is at a reservoir temperature allowing a microbial metabolic pathway of the microbial culture to convert the microbial stimulation fluid into a byproduct to promote dissolution of carbonate compounds in the outer hydrocarbon bearing region, thereby forming a pre-treated zone in the hydrocarbon bearing region having increased porosity and permeability; and operating the thermal recovery well to heat and produce heavy hydrocarbons from the pre-treated zone.

60. The process of claim 59, comprising reducing heat in the heated hydrocarbon depleted zone to achieve the reservoir temperature in the outer hydrocarbon bearing region

61. The process of claim 59 or 60, comprising injecting the microbial stimulation fluid through the thermal recovery well.

62. The process of any one of claims 59 to 61, wherein the thermal recovery well is part of a CSS or SAGD heavy hydrocarbon recovery operation.

63. A system for pre-treating a carbonate reservoir that includes heavy hydrocarbons in preparation for hydrocarbon recovery, comprising.
a pre-treatment well for injecting a microbial stimulation fluid into a region of the carbonate reservoir that includes a microbial culture; and a heating arrangement for heating the region to a reservoir temperature allowing a microbial metabolic pathway of the microbial culture to convert the microbial stimulation fluid into a byproduct to promote dissolution of carbonate compounds in the region, wherein dissolution of the carbonate compounds increases porosity and permeability of the region.

64. The system of claim 63, wherein the pre-treatment well comprises an injection section configured for injecting a gaseous fluid as the microbial stimulation fluid

65. The system of claim 63 or 64, wherein the heating arrangement comprises an aboveground heating device for heating the microbial stimulation fluid prior to injection into the region.

66. The system of any one of claims 63 to 65, wherein the heating arrangement comprises an underground heating device.

67. The system of any one of claims 63 to 66, wherein the heating arrangement comprises a thermal hydrocarbon recovery well adjacent to the region.

68. The system of any one of claims 63 to 67, wherein the microbial stimulation fluid is a gas and the system further comprises an aboveground compressor for compressing the gas for injection.

69. The system of any one of claims 63 to 68, further comprising a temperature measurement device for measuring the temperature of the region.