MICROBIAL ENHANCED TREATMENT OF CARBONATE RESERVOIRS FOR IN SITU HYDROCARBON RECOVERY

FIELD OF THE INVENTION

The present invention generally relates to the field of in situ hydrocarbon recovery and more particularly to techniques for microbial enhanced 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 (Si0 ₂ ), 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 (CaC0 ₃ ), 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 (rtiD) 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 geological 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 (SAGD), 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 techniques for treating a carbonate reservoir with a microbial stimulation fluid including H ₂ to allow microbial production of a byproduct to promote dissolution of carbonate compounds and increase the porosity and permeability of the carbonate reservoir, thereby enhancing hydrocarbon recovery.

In some implementations, there is provided a process including injecting a microbial stimulation fluid including H ₂ into a carbonate reservoir so that at least a portion of the H ₂ enters a region of the carbonate reservoir, wherein the region includes C0 ₂ , hydrocarbons and a microbial culture, such that the microbial culture converts at least part of the H ₂ and the C0 ₂ into a byproduct to promote dissolution of carbonate compounds in the region, thereby increasing porosity of the region; and recovering hydrocarbons from the region of increased porosity.

In some implementations, the process further includes temperature treating the region to a reservoir temperature that promotes a microbial metabolic pathway of the microbial culture to convert the H ₂ and C0 ₂ into the corresponding byproduct.

In some implementations, the temperature treating includes preheating the microbial stimulation fluid to a heated temperature, thereby producing a preheated microbial stimulation fluid, before injection; and heating the region with heat conducted from the preheated microbial stimulation fluid. In some implementations, the temperature of the preheated microbial stimulation fluid is between 15°C and 80°C. The temperature of the preheated microbial stimulation fluid may be between 20°C and 60°C.

In some implementations, the temperature treating includes heating the region of the carbonate reservoir by a separate heat source from the microbial stimulation fluid. The heating of the region by the separate heat source may include operating a thermal in situ recovery operation adjacent to the region, before and/or during the injection of the microbial stimulation fluid. The heating of the region by the separate source may include injecting a heating fluid into or adjacent to the region. The heating of the region by the separate source may include operating a heating device in or adjacent to the region.

In some implementations, the process further includes, after the step of injecting the microbial stimulation fluid, the step of soaking the region for a soak period during which the carbonate compounds dissolve and the porosity of the region is increased. The soaking period may be between about 1 month and about 1 year.

In some implementations, the microbial stimulation fluid further includes C0 ₂ .

In some implementations, the microbial stimulation fluid further includes a carrier fluid. The carrier fluid may be a gaseous carrier fluid. The gaseous carrier fluid may include or be N ₂ . In some implementations, the carrier fluid includes water, a fracturing fluid or a drilling fluid.

In some implementations, the microbial stimulation fluid further includes an additional microbial nutrient.

In some implementations, the microbial stimulation fluid consists of H ₂ and C0 ₂ .

In some implementations, at least part of the C0 ₂ that is converted into the byproduct is natively present in the region of the carbonate reservoir. In some implementations, at least part of the C0 ₂ that is converted into the byproduct is injected into the carbonate reservoir.

In some implementations, the hydrocarbons include heavy hydrocarbons.

In some implementations, the step of recovering the hydrocarbons includes subjecting the region to a Steam-Assisted-Gravity-Drainage (SAGD) recovery operation.

In some implementations, the step of recovering the hydrocarbons includes subjecting the region to a Cyclic-Steam-Stimulation (CSS) recovery operation.

In some implementations, the process includes identifying the microbial culture indigenous to the region of the carbonate reservoir; and providing the microbial stimulation fluid having a composition and temperature based on the identification and such that a microbial metabolic pathway of the identified microbial culture will convert the microbial stimulation fluid to generate the byproduct that promotes dissolution of carbonate compounds in the region.

In some implementations, the microbial stimulation fluid is provided so as to provide pre-determined molar proportions of H ₂ and C0 ₂ available for the microbial culture in accordance with the byproduct to be produced.

In some implementations, the carbonate reservoir includes a stratigraphical unit with sedimentary dolomite and limestone.

In some implementations, the region of the carbonate reservoir includes a dense limestone matrix and at least a portion of the hydrocarbons are in the dense limestone matrix.

In some implementations, the region of the carbonate reservoir has a permeability between 1 mD and 200 mD. The region of the carbonate reservoir may have a permeability between 1 mD and 10 mD.

In some implementations, the step of injecting includes injecting a mixture including the C0 ₂ and the H ₂ as the microbial stimulation fluid. In some implementations, the microbial culture converts the H ₂ and the C0 ₂ into a bioacid as the byproduct.

In some implementations, the bioacid includes formic acid, acetic acid, propanoic acid, butyric acid, or lactic acid, or a combination thereof.

In some implementations, the bioacid includes acetic acid.

In some implementations, the microbial culture includes an acetogen and the metabolic pathway includes the Wood-Ljungdahl pathway, thereby producing the acetic acid as the byproduct.

In some implementations, the microbial stimulation fluid includes the H ₂ and the C0 ₂ in a molar proportion in accordance with the Wood-Ljungdahl pathway for production of the acetic acid.

In some implementations, the C0 ₂ is derived from an in situ hydrocarbon recovery operation, a bitumen mining operation, a bitumen extraction operation, a hydrocarbon upgrading operation, or a power production operation, or a combination thereof.

In some implementations, at least part of the C0 ₂ is injected into the carbonate reservoir and at least part of the injected C0 ₂ is sequestered in the carbonate reservoir.

In some implementations, the microbial culture consists of an indigenous in situ microbial culture. The microbial culture may be anaerobic, thermophilic, halophilic, or barophilic. The microbial culture may be archaea.

In some implementations, the microbial culture includes an acetogen. The acetogen may be a Clostridium, a Thermoanaerobacteriaceae or an Acetobacterium.

In some implementations, the injecting includes injecting the microbial stimulation fluid into the region of the carbonate reservoir.

In some implementations, the injecting includes injecting the microbial stimulation fluid into a remote zone that is spaced away from the region of the carbonate reservoir, such that the microbial stimulation fluid permeates from the remote zone into the region.

In some implementations, the process further includes identifying the region of the carbonate reservoir; identifying one or more of the remote zones located at distances from the region to allow permeation of the microbial stimulation fluid toward the target zones; and injecting the microbial stimulation fluid into the remote zones.

In some implementations, the step of injecting the microbial stimulation fluid into the remote zones is performed at an injection pressure of at least 100 psi.

In some implementations, the region is identified based on having a permeability of at most 100 mD.

In some implementations, the region is identified based on including an oil- wet carbonate matrix.

In some implementations, the injecting of the microbial stimulation fluid is performed through a pre-treatment well.

In some implementations, the pre-treatment well includes at least one vertical well, slanted well, or horizontal well or a combination thereof.

In some implementations, the process further includes terminating injection of the microbial stimulation fluid through the pre-treatment well; and then operating the pre-treatment well as part of the step of recovering hydrocarbons.

In some implementations, the pre-treatment well is operated as a CSS well for recovering hydrocarbons.

In some implementations, the pre-treatment well is operated as part of a SAGD well pair including a SAGD injection well overlying a SAGD production well for recovering hydrocarbons. In some implementations, the pre-treatment well is operated as the SAGD injection well.

In some implementations, the process further includes providing the pre- treatment well as an infill well in a hydrocarbon bearing infill zone in between two steam chambers of previously operating thermal hydrocarbon recovery wells; and operating the pre-treatment well to pre-treat the infill zone.

In some implementations, the process further includes providing a first and a second of the pre-treatment well.

In some implementations, the first pre-treatment well and the second pre- treatment well are provided in a spaced-apart and generally parallel configuration and are separated by an inter-well region.

In some implementations, the process further includes 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 increased porosity; and providing sufficient flow of the microbial stimulation fluid and time to allow the first and second pre-treated zones to expand across the inter-well region and form a common pre-treatment zone having increased porosity.

In some implementations, the first and second pre-treatment wells are operated as CSS wells for the hydrocarbon recovery.

In some implementations, the first and second pre-treatment wells are operated as a SAGD well pair for the hydrocarbon recovery.

In some implementations, the injecting of the microbial stimulation fluid is performed prior to recovering hydrocarbons from the region.

In some implementations, the process includes operating the pre-treatment well as part of a mature or wind-down operation.

In some implementations, the byproduct promotes development of water-wet carbonate particles in the region. In some implementations, the byproduct promotes dissolution of the carbonate compounds in the region sufficiently to increase permeability of the region.

In some implementations, there is provided a process for recovery of heavy hydrocarbons from a carbonate reservoir, including identifying a hydrocarbon bearing region of the carbonate reservoir that includes a microbial culture and C0 ₂ and is positioned between a first hydrocarbon depleted zone and a second hydrocarbon depleted zone; injecting a microbial stimulation fluid including H ₂ into the hydrocarbon bearing region, such that the microbial culture converts the H ₂ and C0 ₂ into a byproduct to promote dissolution of carbonate compounds in the hydrocarbon bearing region, thereby increasing porosity of the region and 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.

In some implementations, hydrocarbons were recovered from the first hydrocarbon depleted zone and the second hydrocarbon depleted zone using a hydrocarbon recovery operation including Steam-Assisted-Gravity-Drainage (SAGD) and the first and second hydrocarbon depleted zones include first and second steam chambers respectively.

In some implementations, hydrocarbons were recovered from the first hydrocarbon depleted zone and the second hydrocarbon depleted zone using a hydrocarbon recovery operation including Cyclic-Steam-Stimulation (CSS).

In some implementations, the hydrocarbon bearing region is heated to a reservoir temperature at least partially with heat from the hydrocarbon recovery operation.

In some implementations, the C0 ₂ is provided to the region by injection into the carbonate reservoir.

In some implementations, there is 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 C0 ₂ and a microbial culture; injecting a microbial stimulation fluid including H ₂ into the hydrocarbon bearing region, wherein the region is at a reservoir temperature allowing the microbial culture to convert at least part of the H ₂ and C0 ₂ into a byproduct to promote dissolution of carbonate compounds in the hydrocarbon bearing region, thereby forming a pre-treated zone in the hydrocarbon bearing region having increased porosity; and operating the thermal recovery well to heat and produce heavy hydrocarbons from the pre-treated zone.

In some implementations, the process includes reducing heat in the heated hydrocarbon depleted zone to achieve the reservoir temperature in the hydrocarbon bearing region.

In some implementations, the process includes injecting the microbial stimulation fluid through the thermal recovery well.

In some implementations, the thermal recovery well is part of a Cyclic-Steam- Stimulation (CSS) or Steam-Assisted-Gravity-Drainage (SAGD) heavy hydrocarbon recovery operation.

In some implementations, there is provided a process for pre-treating a carbonate reservoir including hydrocarbons in preparation for hydrocarbon recovery, including injecting a microbial stimulation fluid including H ₂ into a carbonate reservoir so that at least a portion of the H ₂ enters a region of the carbonate reservoir, wherein the region includes C0 ₂ , hydrocarbons and a microbial culture, such that the microbial culture converts at least part of the H ₂ and the C0 ₂ into a byproduct to promote dissolution of carbonate compounds in the region; and wherein the dissolution of the carbonate compounds increases porosity of the region.

In some implementations, the region of the carbonate reservoir is subterranean.

In some implementations, there is provided a system for pre-treating a carbonate reservoir that includes hydrocarbons in preparation for hydrocarbon recovery, including a pre-treatment well for injecting a microbial stimulation fluid including H ₂ and positioned to allow at least a portion of the injected H ₂ to enter a region of the carbonate reservoir that includes C0 ₂ and 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 at least part of the C0 ₂ and H ₂ into a byproduct to promote dissolution of carbonate compounds in the region, wherein dissolution of the carbonate compounds increases porosity of the region.

In some implementations, the pre-treatment well includes an injection section configured for injecting a gaseous fluid as the microbial stimulation fluid.

In some implementations, the heating arrangement includes an aboveground heating device for heating the microbial stimulation fluid prior to injection into the carbonate reservoir.

In some implementations, the heating arrangement includes an underground heating device.

In some implementations, the heating arrangement includes a thermal hydrocarbon recovery well located adjacent to the region.

In some implementations, the microbial stimulation fluid is a gas and the system further includes an aboveground compressor for compressing the gas for injection.

In some implementations, the pre-treatment well is located in spaced relation away from the region at a distance sufficient to allow the microbial stimulation fluid to permeate into the region.

In some implementations, the pre-treatment well is located at least partially in the region.

In some implementations, the system also includes a temperature measurement device for measuring the temperature of the region. In some implementations, there is provided a use of H ₂ gas for injection into a hydrocarbon bearing region of a carbonate reservoir and microbial conversion with C0 ₂ into a byproduct promoting dissolution of carbonate compounds in the region thereby increasing the porosity of the region.

In some implementations, there is provided a production fluid recovered from a carbonate reservoir, including hydrocarbons; water; a microbial byproduct derived from indigenous microbial conversion of H ₂ and C0 ₂ ; and dissolved carbonate compounds including Ca ²⁺ , CH ₃ COO ^" and HC0 ₃ ^" .

In some implementations, the microbial byproduct includes a bioacid. The bioacid may include formic acid, acetic acid, propanoic acid, butyric acid, or lactic acid, or a combination thereof.

In some implementations, the hydrocarbons include heavy hydrocarbons.

In some implementations, there is provided hydrocarbons obtained by the process as defined hereinabove or herein.

In some implementations, there is provided a process including injecting a gaseous microbial stimulation fluid including an electron donor component into a carbonate reservoir so that at least a portion of the electron donor component enters a region of the carbonate reservoir, wherein the region includes a carbon source, hydrocarbons and a microbial culture, such that the microbial culture utilizes the electron donor component as an energy source for conversion of the carbon source into a byproduct to promote dissolution of carbonate compounds in the region, thereby increasing porosity of the region; and recovering hydrocarbons from the region of increased porosity.

In some implementations, the electron donor component includes H ₂ . The electron donor component may consist of H ₂ .

In some implementations, the carbon source includes C0 ₂ . The carbon source may consist of C0 ₂ .

In some implementations, the gaseous microbial stimulation fluid includes H ₂ and the C0 ₂ is natively found in the region. In some implementations, the gaseous microbial stimulation fluid includes H ₂ and C0 ₂ . The gaseous microbial stimulation fluid may further include a carrier fluid.

In some implementations, the gaseous microbial stimulation fluid is injected into a remote zone located at a distance from the region such that the gaseous microbial stimulation fluid diffuses from the remote zone into the region.

In some implementations, the region of the carbonate reservoir is subterranean.

It should also be noted that implementations and aspects of the processes, systems, uses and products described and illustrated herein may be combined with other implementations and aspects in the present description. For instance, various other aspects and implementations as described above and herein may also be used in connection with the process utilizing a microbial stimulation fluid including an electron donor component 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.

Fig 1 1 is a perspective view of a sample bottle used to monitor production of acetic acid.

Fig 12 is a graph of pH versus time and acetic acid concentration.

Fig 13 is another graph of pH versus time and acetic acid concentration.

DETAILED DESCRIPTION

Various techniques are described that leverage indigenous microbial communities present in a carbonate reservoir for biological conversion of an injected stimulation fluid including H ₂ into organic bioacid compounds sufficient for treating the carbonate reservoir to enhance a subsequent in situ heavy hydrocarbon recovery operation.

"Carbonate reservoirs" should be understood as reservoirs including 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 including, without limitation, any calcite mineral, including calcite (CaC03), magnesite (MgC03), siderite (FeC03), rhodochrosite (MnC03), any dolomite mineral, including dolomite (CaMg(C03)2), ankerite, (Ca(Me,Fe)(C03)2), kutnorite (CaMn(C03)2), and any aragonite mineral including aragonite (CaC03), whiterite (BaC03) and strontianite (SrC03), or carbonate minerals including mixtures or impure forms of the foregoing, including a mixture of calcite and aragonite, or dolomitic limestone. 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 one or more types of hydrocarbons, such as natural gas, light oil, heavy oil and/or bitumen. 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. In addition, the carbonate reservoirs may be subterranean carbonate formations. "Subterranean" as used herein refers to geological topographies located below the surface of the earth. Such topographies may be located at least 10 meters below the surface of the earth, more typically at least one 100 meters below the surface of the earth. The carbonate reservoirs may also be located at a considerable depth, for example at, 1 , 5, or 10 kilometers below the surface or the earth or even deeper.

The term "hydrocarbons" should be understood to mean compounds that include hydrogen and carbon. For example, hydrocarbons includesaturated hydrocarbons (linear or cyclic alkanes) including methane, ethane, propane, butane, pentane, hexane, heptane, octane, nonane, and decane and other linear saturated hydrocarbons of the general formula CnH2n+2; any unsaturated hydrocarbons (linear or cyclic alkenes or alkynes); and any aromatic or polyaromatic hydrocarbons as well as polymers or mixtures of any of the foregoing. Hydrocarbons may also include compounds composed primarily of carbon and hydrogen but additionally having heteroatoms including but not limited to oxygen, nitrogen, sulfur or metal atoms. Examples of such hydrocarbons having heteroatoms include, for example, naphthenic acids and thiophenes. The hydrocarbons may be gases, such as methane or propane for example; liquids, such as hexane or benzene for example; low melting solids, such as paraffin waxes for example; or solids, such as high molecular weight resins or asphaltenes for example; or any other hydrocarbons natively present in geological rock formations. Hydrocarbons may include natural gas; oil including crude oil, heavy crude oil, and light crude oil; petroleum; shale oil; shale gas; and bitumen.

In some scenarios, the carbonate reservoir includes heavy hydrocarbons. In such cases, "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.

Various techniques are described for pre-treating a carbonate reservoir that includes hydrocarbons, optionally heavy hydrocarbons, prior to hydrocarbon recovery from part of the reservoir. A microbial stimulation fluid including H ₂ is injected such that at least part of the injected H ₂ can enter a region of the carbonate reservoir. The H ₂ may be injected directly into the region or into a remote area from which the H ₂ diffuses into the region. The H ₂ injection point may thus be located in a remote zone that is separate from the region to be treated, as the H ₂ can diffuse from the remote zone into the region.

The H ₂ and a carbon source that may be C0 ₂ are microbially converted into a byproduct in the region of the carbonate reservoir. The C0 ₂ may be endogenously present within the region of the carbonate reservoir, typically in the gas phase, or may be provided exogenously. For example, the C0 ₂ may be injected with the H ₂ or separately. At least a portion of the C0 ₂ may be present as a gas or as water-soluble carbonate/bi-carbonate in the region of the carbonate reservoir.

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/or 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, certain microbial cultures are either dormant or substantially inactive and produce little effective byproducts enabling carbonate dissolution. In some scenarios, depending on the microbial culture and the byproduct to be produced, if the region is not at the desired temperature it can be heated to within a desired temperature range. For example, the microbial stimulation fluid can be heated to a temperature such that when injected into the region, the region is warmed to a desired temperature. The temperature of the region can facilitate conversion of the H ₂ and C0 ₂ by the microbial metabolic pathway into a byproduct that promotes dissolution of carbonates. The temperature facilitating 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 H ₂ and C0 ₂ into a carbonate dissolving byproduct. The microbial stimulation fluid is selected to enable the microbial cultures present in the carbonate reservoir to consume at least H ₂ as a component of the fluid and thereby produce the byproduct that promotes dissolution of carbonates present in the region. The microbial stimulation fluid may include H ₂ and C0 ₂ 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/or 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 or permeation 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 H ₂ and C0 ₂ into acetic bioacid according to the following reaction (I):

4H ₂ + 2C0 ₂ ^ CH ₃ COOH + 2H ₂ 0 (I)

It should be noted that the bioacid may include one or more types of organic acids, such as formic acid, acetic acid, propanoic acid, butyric acid, lactic acid, and the like. Formic acid, for example, may be formed through the following reaction (II):

C02 + H2 -> HCOOH (II)

Injection of the microbial stimulation fluid including C0 ₂ and H ₂ gas into or proximate to 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 H ₂ and C0 ₂ in relative proportions according to the metabolic pathway for producing bioacid, acetic acid for example in order to facilitate the metabolic reaction (I) or formic acid in order to facilitate the metabolic reaction (I I).

The bacterial pathway for acetogenesis may be the so-called Wood- Ljungdahl pathway. The acetogens may be those known as Clostridium aceticum, Clostridia in the Thermoanaerobacteriaceae family such as Moorella thermoacetica, and Acetobacterium woodii. Acetobacterium woodii has notably been shown to grow on H ₂ and C0 ₂ 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 H ₂ and C0 ₂ and such additional compounds may be included in the microbial stimulation fluid or present in the carbonate reservoir itself.

It should be noted that the microbial culture may include various anaerobic, thermophilic, halophilic, or barophilic bacterial species, archaea, as well as mixtures including a plurality of species. Microbial cultures capable of catalyzing a reaction involving H ₂ and C0 ₂ to produce an organic acid may be identified by obtaining samples, for example drill cores, and cultivating such cultures and/or analyzing nucleic acid sequences, ribosomal RNAs, for example, or other strain specific characteristics. For instance, samples from geological carbonate formations may be obtained to evaluate the presence of micro-organisms capable of catalyzing H ₂ and C0 ₂ reactions to produce organic acids. Such evaluations may involve incubation of the carbonate sample under anaerobic conditions in the presence of H ₂ and C0 ₂ and monitoring for the presence of the bacterial strain by assaying for organic acids, as outlined in Example 1 . The analytical information obtained from sample evaluation may also be used to optimize the amount of H ₂ and, optionally, C0 ₂ delivered to the carbonate reservoir. Accordingly, the process may include the steps of obtaining a sample from the region of the carbonate reservoir, and identifying within the sample a microbial strain capable of catalyzing a reaction between H ₂ and C0 ₂ to produce an organic acid. The subsequent steps of providing the microbial stimulation fluid may be adjusted based on the assessment of the sample.

As noted above, the microbial culture may include acetogens for example. 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 (III):

CaC0 ₃ + CH ₃ OOH ^ Ca ²⁺ + CH ₃ COO ^_ + HC0 ₃ ^" (III)

The following reactions equations (IV) and (V) are for calcite and dolomite respectively:

2CH ₃ COOH + CaC0 ₃ ^ Ca(CH ₃ COO) ₂ + C0 ₂ + H ₂ 0 (IV)

4CH ₃ COOH + CaMg(C0 ₃ ) ₂ -> Ca(CH ₃ COO) ₂ + Mg(CH ₃ COO) ₂ + 2C0 ₂ +

2H ₂ 0 (V)

The microbial stimulation fluid may be provided so as to provide predetermined molar proportions of the H ₂ and C0 ₂ available for the microbial culture in accordance with the byproduct to be produced and/or the type of carbonate compound to be dissolved. The concentrations of H ₂ and C0 ₂ may be selected so that the maximum production of organic acid results. For example, approximately equimolar amounts of H ₂ and C0 ₂ may be provided to produce formic acid, or a molar ratio of approximately 2:1 of H ₂ and C0 ₂ may be provided to produce acetic acid.

The carbonate formation may be evaluated by assessing the gas composition of a well, determining gas pressure, assessing whether the gas pressure is above or below the bubble point, and/or determining whether a gas cap is present. Based on the findings with respect to the presence of C0 ₂ , the fluid maybe formulated and the H ₂ concentration may be determined and/or adjusted. The process may therefore include a step of evaluating the presence of C0 ₂ in the carbonate formation and then injecting a corresponding amount of H ₂ to achieve the desired bioacid production. For example, where the in situ concentration of C0 ₂ has been determined to be 5 mM, the H ₂ concentration used may be 5 mM to form formic acid or 10 mM to form acetic acid.

In some scenarios, the microbial cultures may be present within water containing portions of the carbonate region such as fractures, cleats, capillaries and water-hydrocarbon contact points. The selected carbonate region may therefore additionally include water.

The temperature of the region for the formation of bioacid may be increased or decreased in order to be within a desired range or in order to condition the region to promote the microbial community. It should be understood that the temperature may be between about 1 °C and about 120°C, and may optionally be between 30°C and 90°C. In some scenarios, the temperature of the region for acetogenesis may be provided in a range promoting conversion of H ₂ and C0 ₂ gas into acetic bio-acid. 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.

The microbial stimulation fluid may be injected in various ways depending for example on the properties of the fluid. In some scenarios, the fluid is a gas including gas phase H ₂ and may be handled and injected using appropriate gas injection equipment. Alternatively, the H ₂ may be provided dissolved in a liquid, which may be water, an aqueous liquid such as drilling fluid or fracturing fluid, other another type of liquid.

The H ₂ may be delivered by providing the H ₂ to a surface wellhead connection where the H ₂ may be injected into the casing-tubing annulus of the well and/or in the tubing string. Upon injection, the H ₂ migrates down the casing-tubing annulus or tubing string to distal locations, which, if injected in the casing-tubing annulus, may include one or more subsurface injection valves that convey the H ₂ to the tubing string. At one or a plurality of distally located apertures in the tubing line, the H ₂ effuses from the tubing to enter the geological rock formation by flow and/or diffusion and disperses through the geological rock formation to comingle with the C0 ₂ present at the carbonate formation and be microbially converted into the organic acid. In this respect the "injection point" may be seen as the point where the H ₂ enters the geological rock formation in a form free to react with C0 ₂ . The H ₂ can react with C0 ₂ in situ in the region within the carbonate formation. The "reaction location" may be seen as the point in the carbonate formation where H ₂ reacts with C0 ₂ . The injection point may be located in spaced relation from the reaction location. The reaction location may, for example, be a region located about 1 to 2 meters away from the injection point, it may be located about 100 to 200 meters away from the injection point, or it may be located as far as 1 to 2 kilometers away from injection point. A reaction location within the carbonate formation is reached following dispersal of the H ₂ from the injection point. When the process is used in conjunction with a fracturing operation, the reaction location may be several kilometers removed from the injection point.

In order to achieve H ₂ dispersal to remote locations away from the injection point, the H ₂ may be injected under pressure. The pressures used may be a function of the residual pressure in the carbonate formation which must be overcome. Pressures may be kept below the fracturing pressure, unless it is intended to combine the process with fracturing. Injection pressures at the wellhead may range from about 10 psi to about 10,000 psi. The pressure at the wellhead may be about 100 psi. The pressure may also be varied and it should be understood that by increasing the pressure used to inject H ₂ , dispersal of H ₂ to reaction locations located more remotely from the injection points may be achieved.

The amount, concentration, pressure, temperature, injection cycle and flow rate of the H ₂ may vary. The H ₂ may be injected continuous or intermittently. The concentration of H ₂ should be sufficient to form the byproduct (e.g., bioacid) by microbial in situ reaction with carbon dioxide. The concentration of H ₂ may be between about 1 mM to about 100 mM, depending on the concentration of C0 ₂ and bicarbonate. The concentration of H ₂ may be optimized or adjusted, for example by preparing a plurality of samples, each including a different H ₂ concentration; injecting each sample into a geological carbonate formation or corresponding core sample; and measuring the organic acid and/or hydrocarbon production in situ in the carbonate formation. Then, a H ₂ concentration may be selected that provides enhanced organic acid and/or hydrocarbon production. Other operating parameters, such as temperature, may similarly be determined for enhancement purposes. There may be variation in optimal conditions, including the H ₂ concentration, depending on the carbonate formation that are treated and from which the hydrocarbons are and one may further enhance the hydrocarbon recovery efficiency by enhancing the operating parameters relating to the delivery of H ₂ on a case-by-case basis. It should be noted that various methodologies and equipment may be used to deliver H ₂ into the carbonate reservoir.

In addition, after injection of the microbial stimulation fluid there may be a soaking time that is provided prior to commencing hydrocarbon recovery. For example, hydrocarbon recovery may be delayed until at least 2 days after injection of the H ₂ . In other scenarios, the hydrocarbon recovery is not initiated until at least 10 days, 20 days, 30 days, 60, 160, 320 days, one year or more following delivery of H ₂ into the carbonate reservoir. In some scenarios, the soaking period may be between about 1 month and about 12 months.

Some 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, in order to not 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 and other microbial strains can be destroyed. However, some acetogens have been found to have highly resistive spores up to 120°C-140°C. Furthermore, some acetogenic bacteria and other microbial strains 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 be 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 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 as 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 C0 ₂ 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 produce 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 an injected mixture of C0 ₂ and H ₂ , though it may be an alternating injection of H ₂ and C0 ₂ or injection of the two gases via two distinct pre- treatment wells into the same target zone. In some scenarios, when C0 ₂ is injected into the carbonate reservoir, some of the injected C0 ₂ participates with H ₂ in the formation of the byproduct and some of the injected C0 ₂ is sequestered in the carbonate reservoir. In some other scenarios, the C0 ₂ that participates with H ₂ in the formation of the byproduct was previously injected into the carbonate reservoir as part of a C0 ₂ sequestration operation. 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, FCSS, 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 infill zone 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 infill zone 22 may also be referred to as an unrecovered hydrocarbon bearing zone or a bypassed zone 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 infill 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 infill 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 infill 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 infill 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 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 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 infill zone 22 and at least partially reaches a location proximate to 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.

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 bioacid production, e.g. acetogenesis, for instance by providing a pH value above about 5. Heating to 60°C or 100°C, for example, may induce acetogens to form spores while destroying other strains. The acetogen spores will activate upon cooling. In other words, the region of the carbonate reservoir may be pre-conditioned by heating in order to favor desired microbial community for subsequent bio-acid formation. The preconditioning may include a heat treatment to promote activity or growth of bio-acid forming microbes and/or reduce or prevent competing microbial activity that would be undesirable. In addition, providing an excess of a certain substrate may allow acetogens to outcompete other microbes that may be present. Hence, the temperature, the composition of the fluid and the injection rate of the fluid may be controlled, adjusted or provided to achieve such favorable 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 C0 ₂ and the energy source may include H ₂ . The microbial stimulation fluid may include non-condensable gases, such as C0 ₂ and H ₂ , 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, warm 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. Additional agents may be provided as part of the injected fluid or delivered to the region separately. For example, the fluid may include a carrier gas such as N ₂ , which may represent between about 60% (v/v) and about 90% (v/v), between about 70% (v/v) and about 85% (v/v), or about 80% (v/v); or a carrier liquid in which H ₂ and/or C0 ₂ may be dissolved, including water, fracturing fluids or drilling fluids. Further additional agents may include selenite, tungstate, phosphate, or ammonium. Additional chemical agents that may be delivered to the delivery site include gelling agents, corrosion inhibitors, propping agents, solvents, biocides limiting growth of biomass formation in the tubing and/or at the well bore region, and the like. Where endogenous microbial strains are used, these additional agents may be selected to be compatible with growth of these endogenous strains.

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 C0 ₂ and H ₂ promoting rapid production of bioacid, which may include acetic acid, 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 bioacid or product ions of reaction (III) 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 C0 ₂ and H ₂ 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 is 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 due to absorption of sunlight. 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 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 so 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; 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 microbially 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 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.

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 C0 ₂ , 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 C0 ₂ sequestration by injecting C0 ₂ into the carbonate reservoir.

As mentioned above, some of the techniques describe herein may be used in conjunction with fracturing methodologies. The microbial pre-treatment techniques may be used prior to fracturing in order to enhance and widen existing natural fractures and pores in the carbonate formations. The microbial pre-treatment techniques may also be used contemporaneously with fracturing in order to further increase the permeability of growing fractures and pores. The microbial pre-treatment techniques may be used following fracturing to further increase the size of the fracture generated by the fracturing operation and to increase the permeability of the rock matrix adjacent to the fracture. Appropriate care may also be taken to prevent collapse of the fracture due to a loss of proppants during di-hydrogen injection.

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.

EXAMPLES & EXPERIMENTATION

Example 1 : Production of acetic acid from carbon dioxide and hydrogen diffusing through oil

Samples were obtained from the Medicine Hat Glauconitic C (MHGC) field near Medicine Hat, Alberta. This is a shallow (850 m), low temperature (30Ό) field that produces heavy oil (API of 16 ^* ) from pre dominantly sandstone reservoir rock by water injection (Voordouw, G., et al. (2009) Environmental Science and Technology, Vol. 43, pp. 9512-9518; Agrawal, A. et al. (2012) Environmental Science and Technology, Vol. 46, pp. 1285-1292, 2012). Produced waters from producing wells 5 and 16 (5-PW and 16-PW) were collected in a 1 L Nalgene bottle that was filled to the brim to exclude air. Upon arrival in the lab these samples were stored in a Coy anaerobic hood with an atmosphere of 90% N ₂ and 10% C0 ₂ . To 159 mL serum bottles, 5 mL of sample (5-PW or 16-PW) and 45 mL of acetogen medium were added. A layer of 10 mL of heavy oil (HO, 2300 cP at 20Ό) o r light oil (LO, 3.5 cP at 20Ό) was then added. The bottles were closed with butyl rubber stoppers and filled with a headspace of 80% H ₂ and 20% C0 ₂ . H ₂ -C0 ₂ gas was regularly added and acetic acid and methane production was regularly monitored. Experiments were also done without oil. The gas headspace and the aqueous phase could be sampled through separate sampling ports without disturbing the intervening oil layer (see Fig 1 1). The results of oil- containing incubations (47 days) are summarized in Table 1. Significant concentrations of acetic acid (approximately 10 to 20 mM) and methane (approximately 5 to 8 mM) were formed under all incubation conditions of this experiment. The only difference was in the volume of gas used, which was higher in the absence of oil (235 to 260 mL) than in the presence of LO (144 to 164 mL) or HO (53 to 84 mL). One would expect similar volumes of gas to be used for production of similar concentrations of acetic acid and methane. Possible dissolution of H ₂ and C0 ₂ in the oil phase when the experiment was started may explain this difference. The data in Table 1 show that acetic acid was readily formed in an aqueous phase even if the substrates H ₂ and C0 ₂ needed to diffuse through an intervening oil phase of considerable viscosity.

Table 1. Formation of aqueous phase acetic acid from gas phase H ₂ and C0 ₂ , separated from the aqueous phase by a layer of oil. The formation of methane in the gas phase and H ₂ -C0 ₂ gas usage is also indicated. Data were obtained following 47 days of incubation.

Example 2. Dissolution of carbonate minerals with acetic acid

In order to demonstrate dissolution of carbonate minerals with acetic acid, a sample of calcium carbonate and a sample of oilfield core material were incubated with acetic acid. The experiment was performed by adding 100 μΙ amounts of 4 or 17.5 M acetic acid to a mixture of 10 mL deionized water and 0.50 g of calcium carbonate (CaC0 ₃ ; 500 mM) and sample crushed core in a glass vial under stirring. The chemical reaction was monitored by measuring pH as a function of time. Following completion of the reaction, vacuum filtration was used to collect undissolved CaC0 ₃ on an 0.2 μηι Millipore filter. The resulting solid was dried at 100 for 2 hours , allowed to cool down to room temperature and then weighed.

The results of the experiment with CaC0 ₃ are shown in Fig 12. The suspension of CaC0 ₃ in water had a pH of 10, decreasing to 9.2 over 102 minutes of monitoring. The pH decreased to 5.8 following addition 40 mM acetic acid, then increased during the 90 minute period of monitoring. Each addition of acetic acid to the indicated concentration caused a drop in the pH followed by gradual increase, which corresponded to dissolution of CaC0 ₃ . Addition of acetic acid to a final concentration of 1020 mM and a final pH of 5.3 over 932 minutes led to dissolution of 94% of the CaC0 ₃ (0.0314 g remained undissolved).

The results of the experiment with crushed carbonate core are shown in Fig 13. The pH of a suspension of 0.5 g of core in 10 ml of water was 9.8 and this decreased to 3.2 with addition of 175 mM acetic acid. The pH then gradually increased until subsequent additions of acetic acid were done to a final concentration of 1045 mM and a final pH value of 5.34 in 1626 minutes. The remaining amount of undissolved core was 0.172 g, corresponding with a percentage of weight loss of 66%.

These experiments show that acetic acid rapidly reacts with calcium carbonate as well as with carbonate core. The latter was not dissolved as completely as calcium carbonate, presumably because it contains minerals other than carbonates, which do not dissolve in acetic acid.