MICROBIAL PROCESSES FOR INCREASING FLUID MOBILITY IN A HEAVY OIL RESERVOIR

Methods are provided for increasing overall fluid mobility in a near-wellbore region in an oil sands reservoir, for example in a reservoir having an inter-well region between a first well and a second well of a well pair in which at least a portion of the near-wellbore region is within the inter-well region. The methods may involve inoculating the near-wellbore region with a microorganism, wherein the near-wellbore region comprises a hydrocarbon phase and an aqueous phase, the viscosity of the hydrocarbon phase being greater than the viscosity of the aqueous phase. Conditions may be maintained in the near-wellbore region so that the microorganism metabolizes at least a portion of the hydrocarbon phase so that saturation of the near-wellbore region by the hydrocarbon phase decreases and saturation of the near-wellbore region by the aqueous phase increases.

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Description
CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of priority of U.S. Provisional Patent Application No. 61/721,452 filed Nov. 1, 2012, which is incorporated herein by reference in its entirety.

FIELD

The invention relates generally to in situ processes for recovering hydrocarbon from oil sands, and particularly to processes for increasing fluid mobility by inoculating a near-wellbore region in an oil sand reservoir with one or more microorganism.

BACKGROUND

Demand for crude oil in North America has outstripped production levels for the last several decades. Conventional oil recovery practices are only able to recover 50% of the total oil present in even the most favourable reservoirs. Conventional recovery levels in less favourable reservoirs, including heavier oil and bitumen reservoirs, can be 10% or less. So-called “enhanced oil recovery” techniques can help access some fraction of total oil or bitumen unavailable by conventional methods. These include: thermal processes, employing, for example, steam, hot water, solvent, or a combination thereof to heat the reservoir and reduce the viscosity of heavier oil; and non-thermal processes, which include using substances (e.g., solvents, polymers, acids, surfactants) to reduce the viscosity of the oil, increase the viscosity of displacing fluids, reduce interfacial tension between the oil and displacing fluids, and degrade rock formations to allow smoother displacement of oil.

One example of an enhanced in situ oil recovery technique is steam-assisted gravity drainage (“SAGD”). SAGD is a known thermal approach to producing bitumen and heavy crude oil from reservoirs. It involves drilling two vertically-displaced (typically about 5 m apart), parallel, horizontal wells into, for example, the lower portion of an oil reservoir. Steam is gradually injected into the reservoir via the upper well (i.e., the injector well). The high temperature of the steam affords a transfer of heat between the steam and the bitumen or heavy crude oil in the surrounding formation, leading to a decrease in viscosity of the bitumen or heavy crude oil. Gravitational forces gradually displace oil and bitumen to the lower well (i.e., the producer well). The producer well collects hydrocarbons, such as oil or bitumen, and any water from the condensation of injected steam, from whence they are removed to the surface and fractionated. Steam injection can occur continuously or discontinuously. As steam rises upward and expands outward more oil and bitumen are gradually displaced towards the lower well, where production occurs. SAGD improves significantly upon conventional recovery methods: the low steam pressure means that fracturing between the wells is unlikely to occur; leaking of steam into the producer well occurs at a low rate; and the overall process is relatively efficient, resulting in recovery of up to 80% of the total oil or bitumen in place in some reservoirs. The state of a formation at which any fluid such as bitumen, oil, water or gas may travel through the region between the two wells (referred to herein as the inter-well region or inter-well space), thereby connecting one well to the other and vice versa, is the state at which “injector-producer communication” is achieved. Typically injector-producer communication (which is also referred to herein as fluid communication or communication) is achieved when the inter-well region is heated. In some reservoirs (particularly those that have little or no underlying aquifer), a long period of heating is normally required to achieve initial communication (“start-up”) of fluids between the injector and producer. Methods of shortening the time to inter-well communication (which is also referred to as “accelerating start-up”) have previously been considered, including, for example, by lowering bitumen or oil viscosity (see, for e.g., U.S. Pat. No. 7,934,549).

Methods to enhance oil recovery that incorporate microorganisms have been described. In situ methods that employ microorganisms to dislodge oil from rock formations, or otherwise enhance the recovery of oil from reservoirs, are known as “microbial-enhanced oil recovery” (“MEOR”) techniques. MEOR methods have many useful applications, including, for example: producing biopolymers that increase viscosity of waterfloods (see, for e.g., U.S. Pat. No. 4,475,590 to Brown), and producing biosurfactants (see, for e.g., U.S. Pat. No. 4,522,261 to McInerney et al.).

U.K. Patent No. 2,450,502 to Kotlar describes methods for enhancing heavy oil recovery from a reservoir using a microorganism capable of lowering oil viscosity. Kotlar indicates that microorganisms be injected during or after an extraction process. U.S. Pat. No. 8,235,110 to Larter et al. describes general methods of using a preconditioning agent in a mobile water film to precondition oil reservoirs.

The following publications describe methods which employ microorganisms for production or treatment of oil: Canadian Patent Application No. 2,638,451; Canadian Patent No. 2,761,048; Canadian Patent No. 2,531,963; Canadian Patent No. 1,317,540; Canadian Patent No. 2,100,328; U.S. Patent Publication No. US/2013/0062053; U.S. Patent Publication No. US/2012/0325457; U.S. Patent Publication No. US/2012/0261117; U.S. Patent Publication No. US/2012/0301940; U.S. Patent Publication No. US/2012/0214713; U.S. Patent Publication No. US/2011/0257052; U.S. Patent Publication No. US/2011/0083843; U.S. Patent Publication No. US/2011/0067856; U.S. Patent Publication No. US/2010/0212888; U.S. Patent Publication No. US/2011/0308790; U.S. Patent Publication No. US/2010/0012331; U.S. Pat. No. 7,922,893; PCT Publication No. WO2011/076925; U.S. Patent Application No. US/2009/0130732. U.S. Pat. No. 5,174,378; Harner et al., J. Ind. Microbiol. Biotechnol. 2011; November: 38(11):1761-1775; PCT Publication No. WO/2011/159924; PCT Publication No. WO/2008/070990; Canadian Patent Application No. 2,640,999; Canadian Patent Application No. 2,767,846; Canadian Patent Application No. 2,823,752; and Canadian Patent Application No. 2,823,750.

SUMMARY

In various embodiments, methods are provided which increase overall fluid mobility in a near-wellbore region in an oil sands reservoir. The near-wellbore region may for example be within an inter-well region between a first well and a second well of a well pair, or alternatively may be a single well that is not a component of a well pair. Accordingly, for embodiments where the near-wellbore region is proximal to one or both wells of a well pair, the method may involve increasing overall fluid mobility in the inter-well region between the first well and the second well of the well pair, for example in connection with start-up process associated with SAGD production methods.

In one aspect, the method increases overall fluid mobility in a near-wellbore region in an oil sands reservoir. The method involves (a) inoculating the near-wellbore region with one or more microorganism, wherein the near-wellbore region comprises a hydrocarbon phase and an aqueous phase, the viscosity of the hydrocarbon phase being greater than the viscosity of the aqueous phase; and (b) maintaining conditions in the near-wellbore region so that the one or more microorganism metabolizes at least a portion of the hydrocarbon phase so that saturation of the near-wellbore region by the hydrocarbon phase decreases and saturation of the near-wellbore region by the aqueous phase increases, increasing overall fluid mobility.

In one embodiment, the method increases the overall fluid mobility in an inter-well region between a first well and a second well of a well pair in the oil sands reservoir, wherein the near-wellbore region is associated with at least one of the first and second well, and at least a portion of the near-wellbore region is within the inter-well region. For example, the first well may be an injection well, and the second well may be a production well. In other embodiments, the method increases overall fluid mobility in the region of a single well located in the oil sands reservoir which is not a component of a well pair.

In some aspects, inoculating may occur prior to steam-assisted gravity drainage (SAGD) to pre-condition the oil sands reservoir for SAGD. Optionally, the inoculating may occur after SAGD is completed. Further, the instant process may be used as an alternative to SAGD, and thus inoculating may occurs in lieu of SAGD in an oil sands reservoir from which oil may subsequently be produced. The method may be used in association with thermal recovery methods, generally, such as cyclic steam stimulation (CSS), and/or other recovery methods involving in situ drilling.

Maintaining propagating conditions in at least a portion of the inter-well region may be undertaken so as to ensure viability of the microorganism within the inter-well region. Such conditions may permit the microorganism to metabolize at least a portion of the hydrocarbon phase, thereby decreasing saturation of the inter-well region by the hydrocarbon phase and increasing saturation of the inter-well region by the aqueous phase.

According to another aspect, a cycling process may be employed comprising: (c) injecting or circulating a heated cycling fluid within one or both of the first or second well in fluid communication with the near-wellbore region, to mobilize fluids within the near-wellbore region; and (d) repeating steps (a) and (b) so that the microorganism metabolizes a further portion of the hydrocarbon phase. Optionally, the cycling process steps (c) and (d) may be repeated more than once. The cycling process steps may be repeated for a period of time, such as for about two weeks or more. The heated cycling fluid may comprise steam or water, optionally with a solvent, surfactant, or a combination thereof.

The one or more microorganism may be contained in an inoculant solution, and following step (a) the inoculant solution may be absorbed into the near-wellbore region over a soaking period. Optionally, after the soaking period, additional inoculant solution can be added into the near-wellbore region well to increase overall fluid mobility. Optionally, unabsorbed inoculant solution can be withdrawn from the near-wellbore region after the soaking period; and may be combined with the additional inoculant solution for adding and re-circulating in the near-wellbore region. An exemplary total volume of inoculant solution, including that used in step (a) plus the additional inoculant solution, when utilized, may be from about 2× to about 3× the volume of the volume of inoculant solution used in step (a).

In aspects of the method, the saturation of the near-wellbore region by the aqueous phase can increase by amounts of 5% or greater, 10% or greater, for example about 25% or greater. A decrease in the hydrocarbon phase saturation is also observed. As an example, the saturation of the near-wellbore region by the hydrocarbon phase may decrease by about 50% after a period of about two weeks. In certain reservoirs with high irreducible water saturation, the increase in water saturation observed may not be as great of a percentage increase, because of the high initial aqueous phase saturation.

Fluid communication may be established between the first well and the second well of a well pair upon completion of step (a) and (b). Subsequently, injecting or circulating a fluid in: (i) the first well; (ii) the second well; or (iii) both the first well and the second well to establish the fluid communication between the first well and the second well may be conducted, using a fluid such as steam or water, optionally including a solvent, a surfactant, or combinations thereof.

Aspects of the method may involve determining a first saturation level of the aqueous phase in the near-wellbore region prior to inoculating, and determining a second saturation level of the aqueous phase in the near-wellbore region following inoculating, and optionally determining the increase in aqueous phase saturation.

Further aspects of the method may involve determining a first fluid mobility level of in the near-wellbore region prior to inoculating, and determining a second fluid mobility level in the near-wellbore region following inoculating, and optionally determining the increase in fluid mobility.

The one or more microorganism may, for example, be one which can metabolize hydrocarbons of C16 or greater. The microorganism may be one which preferentially metabolizes hydrocarbons of C20 or greater. The inoculant may comprise microorganisms in the form of a mixture of bacteria. The mixture may preferentially metabolize heavy ends of the oil in the oil sands reservoir, and may comprise both aerobic and anaerobic bacteria.

Some aspects of the method involve step of injecting heated fluid into the injection well or circulating heated fluid in the well pair prior to the step of inoculating. The wells in the well pair each may have a section that extends substantially in a horizontal direction, wherein fluid communication is established between the substantially horizontal sections. The substantially horizontal sections of the wells may be substantially parallel, and vertically spaced apart.

According to a further aspect, there is provided herein a method of recovering hydrocarbon from in an inter-well region in an oil sands reservoir located between an injection well and a production well. The method comprises (a) inoculating the inter-well region with a mixture of anaerobic and aerobic bacteria that metabolizes hydrocarbons of C16 or greater; (b) maintaining the viability of at least a portion of the mixture of bacteria in the inter-well region so that the mixture of bacteria metabolizes at least a portion of the hydrocarbon phase having C16 or greater, to produce a hydrocarbon phase of decreased viscosity; and (c) recovering the hydrocarbon phase of decreased viscosity from the inter-well region. Optionally, steps (a) to (c) may be repeated. In some embodiments, the inoculating of the inter-well region comprises injecting the mixture of bacteria into the injection well together with a suitable carrier.

There is described herein a method of increasing overall fluid mobility of oil in a near-wellbore region in an oil sands reservoir, comprising inoculating a well with an inoculant solution comprising one or more microorganism that metabolizes hydrocarbon of C16 or greater; permitting the inoculant solution to become absorbed into the near-wellbore region over a soaking period; and adding additional inoculant solution into the well to increase overall fluid mobility of oil. Optionally, the method may include withdrawing unabsorbed inoculant solution after the soaking period; and combining the withdrawn solution with the additional inoculant solution added into the well to re-circulate in the well. According to an exemplary embodiment, the total volume of inoculant solution used in the steps of inoculating and adding may be at least about 3× the volume used in the step of inoculating. An exemplary soaking period may be from about 2 to about 3 weeks.

Other aspects and features will become apparent to those ordinarily skilled in the art upon review of the following description of specific embodiments as detailed in the accompanying figures, and as described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures illustrate embodiments, by way of example only.

FIG. 1 depicts the geometry of a bottom-water system simulation as described herein.

FIG. 2 depicts wellhead pressure as a function of time for a bottom-water simulation (Sw=25%) as described herein.

FIG. 3 depicts casing and tubing pressure in the well at 12.5 d (bottom-water geometry, Sw=25%) as described herein.

FIG. 4 depicts the geometry of a side-water system simulation as described herein.

FIG. 5 depicts casing and tubing pressure in the well at 12.5 d (side-water geometry, Sw=37%) as described herein.

FIG. 6 depicts casing and tubing pressure in the well at 12.5 d (side-water geometry, Sw=37%) as described herein.

FIG. 7 depicts maximum tubing well head pressure as a function of water saturation in a transition zone.

FIG. 8 depicts the geometry of a generic two well SAGD system simulation as described herein.

FIG. 9 depicts the wellhead casing pressure for the two well system as a function of time.

FIG. 10 depicts casing and tubing pressure in the injector well at the end of 12 d as described herein.

 DETAILED DESCRIPTION

Embodiments of in situ processes for recovering hydrocarbon from oil sands are described herein. In particular, processes for increasing fluid mobility by inoculating a near-wellbore region in an oil sand reservoir with one or more microorganism are described. In alternative embodiments, the processes may for example increase fluid mobility near both horizontal and vertical wells, near a single well, and/or between well pairs. Well pairs may include both parallel well pairs and cross well pairs. The methodology described herein may be used in association with and/or in lieu of thermal recovery methods such as steam-assisted gravity drainage (SAGD) or cyclic steam stimulation (CSS), involving well pairs or a single well.

In various aspects, the implementation of microbial processes are employed so as to adjust oil and water saturation levels in a reservoir. Oil saturation is the fraction of the pore space occupied by oil. Most oil reservoirs also contain some connate water. Oil saturation is rarely 100% and usually ranges from 10% to 90% (in what are known as oil/water “transition zones”). Water saturation is the fraction of the pore space occupied by water. Most reservoirs are water wet and contain connate water. Water saturation may range from 10% to 50% for an oil or gas reservoir and is up to 100% in an aquifer.

One embodiment involves methods of increasing overall fluid mobility in an inter-well region between a first well and a second well of a well pair in an oil sands reservoir. The reservoir may be characterized as having a near-wellbore region associated with at least one of the wells, at least a portion of the near-wellbore region being within the inter-well region.

In selected embodiments, having a well pair wherein the inter-well distance is X meters, the near-wellbore region can be defined as the volume of reservoir occupied within a radius of X/2 m from the wellbore(s) in question. For example, for a well pair in which the wells are 5 m apart, the near-wellbore region may be defined to include up to a 2.5 m radius from each of the two wellbores. In some embodiments, the near-wellbore region includes the volume defined by a radius of 2-3 m from the well, wherein this 2-3 m radius is not necessarily constant (i.e. is variable) along the length of the wellbore. In general, it will be appreciated that the near-wellbore region contains the wellbore.

Selected methods involve: inoculating the near-wellbore region with a microorganism, wherein the near-wellbore region comprises a hydrocarbon phase and an aqueous phase, the viscosity of the hydrocarbon phase being greater than the viscosity of the aqueous phase. The method further involves maintaining conditions in the near-wellbore region so that the microorganism metabolizes at least a portion of the hydrocarbon phase so that saturation of the near-wellbore region by the hydrocarbon phase decreases and saturation of the near-wellbore region by the aqueous phase increases.

The near-wellbore region may for example be associated with: (i) an injector well of the well pair, (ii) a producer well of the well pair, or (iii) both the injector well and the producer well. A single production well may also be associated with the near-wellbore regions, such as utilized in Wedge Well™ technology, which employs a horizontal well in association with a SAGD operation. The near-wellbore region may also be a single well, for example one associated with cyclic steam stimulation (CSS) in which steam is pumped down a vertical well to soak or liquefy the bitumen, which is subsequently pumped to the surface through the same well. The regions nearby either a single well or associated wells (for example, well pairs) are encompassed as the near-wellbore region.

Methods may involve maintaining propagating conditions in at least a portion of the near-wellbore and inter-well regions so that the microorganism propagates within the inter-well region between the first well and the second well, the portion of the inter-well region comprising a hydrocarbon phase and an aqueous phase, the viscosity of the hydrocarbon phase being greater than the viscosity of the aqueous phase.

As used herein, the term “propagating conditions” includes those fundamental chemical and biological factors which are required for maintaining viability of a microorganism, such as a bacterium, including the ability to metabolize hydrocarbons. Without limitation, “propagating conditions” include the following: an appropriate nitrogen source, an appropriate phosphorous source, and an appropriate carbon source, which can include but is not limited to the hydrocarbon in the oil sands reservoir. Without limitation, “propagating conditions” further includes the following an appropriate oxygen source; for example, an aerobic bacterium would require an appropriate oxygen source. Without limitation, “propagating conditions” further includes: an appropriate moisture level, an appropriate pH, and an appropriate temperature. In the case of bacterial microorganisms, “propagating conditions” may further include trace metals or salts such as magnesium or sulfur. The foregoing examples are provided as examples only and are not meant to limit the foregoing.

The method may further involve maintaining propagating conditions in the inter-well region so that the microorganisms metabolizes at least a portion of the hydrocarbon phase so that saturation of the inter-well region by the hydrocarbon phase decreases and saturation of the inter-well region by the aqueous phase increases.

The method may further involve a cycling process involving a subsequent step of injecting or circulating a heated fluid within one or both of the first or second well in fluid communication with the near-wellbore region, so as to mobilize fluids within the near-wellbore region; and then, repeating the steps of inoculating the near-wellbore region and maintaining conditions in the near-wellbore region so that the microorganism metabolizes a further portion of the hydrocarbon phase. The cycling process may be repeated one or more times. The heated cycling fluid may be steam. The heated cycling fluid may be water. The heated cycling fluid may be or may contain a solvent or a surfactant.

The method may be carried out so that saturation of the near-wellbore region by the aqueous phase increases to about 25% or greater, for example up to and including about 3 to 5% above the irreducible water saturation. An exemplary range may be from about 25% to about 37%. The method may be carried out so that saturation of the inter-well region by the aqueous phase increases to about 25% or greater, for example up to and including about 3 to 5% above the irreducible water saturation. An exemplary range may be from about 25% to about 37%. The method may be carried out so that fluid communication is achieved between the first and second wells.

The method may further involve injecting a fluid into or circulating a fluid in: (i) the first well; (ii) the second well; or (iii) both the first well and the second well to achieve fluid communication between the first and second wells. The fluid may be any one or more of the following: steam, water, a solvent, or a surfactant.

The method may further involve determining a first saturation level of the aqueous phase in the near-wellbore region prior to inoculating the near-wellbore region. The method may further involve determining a first saturation level of the aqueous phase in the inter-well region prior to inoculating the near-wellbore region. The method may further involve determining a second saturation level of the aqueous phase in the near-wellbore region following inoculation of the near-wellbore region. The method may further involve determining a second saturation level of the aqueous phase in the inter-well region following inoculation of the near-wellbore region. The method may further involve determining a first mobility level of the aqueous phase in the near-wellbore region prior to inoculating the near-wellbore region. The method may further involve determining a first mobility level of the aqueous phase in the inter-well region prior to inoculating the near-wellbore region. The method may further involve determining a second mobility level of the aqueous phase in the near-wellbore region following inoculation of the near-wellbore region. The method may further involve determining a second mobility level of the aqueous phase in the inter-well region following inoculation of the near-wellbore region.

The method described herein may further involve a step of injecting a heated fluid into or circulating a heated fluid in the first or second well or both prior to the step of inoculating. The wells in the well pair described herein may each have a section that extends substantially in a horizontal direction, the substantially horizontal sections of the wells being oriented in a range from being substantially parallel to substantially perpendicular, and wherein fluid communication may be established between the substantially horizontal sections. The substantially horizontal sections of the wells may be vertically spaced apart. Alternatively, the wells in the well pair described herein may each have a section that extends substantially in a vertical direction, the substantially vertical sections of the wells being substantially parallel, and wherein fluid communication may be established between the substantially vertical sections. The substantially vertical sections of the wells may be horizontally spaced apart. The distance between the substantially horizontal or vertical sections of the wells may for example be about 3 meters. In some embodiments, the first well may for example be an injection well completed for a steam-assisted gravity drainage process and the second well may be a production well completed for a steam-assisted gravity drainage process.

As used herein, the term “light ends” means a fraction of hydrocarbons from oil sands oil having about 20 carbons or fewer, and the term “heavy ends” means a fraction of hydrocarbons from oil sands oil having made up of hydrocarbons having about 20 carbons or more.

The method described herein may further involve a step of injecting a heated fluid into or circulating a heated fluid in one or both of the first or second well prior to the step of inoculating. The wells in the well pair described herein may each have a section that extends substantially in a horizontal direction, the substantially horizontal sections of the wells being substantially parallel, and wherein fluid communication may be established between the substantially horizontal sections. The substantially horizontal sections of the wells may be vertically spaced apart. The distance between the substantially horizontal sections of the wells is about 3 meters, wherein the first well may be an injection well completed for a steam-assisted gravity drainage process and the second well may be a production well completed for a steam-assisted gravity drainage process.

It would be understood by a person of skill in the art that where fluid mobility is increased between well pairs, as determining the spacing of these well pairs is well known in the art. Typically, well pairs may be spaced about 3 to 8 m apart. Alternatively, well pairs may be spaced about 3-7 m apart, 3-6 m apart, 3-5 m apart, 3-4 m apart, or about 3 m apart.

Similarly, any range of values given herein is intended to specifically include any intermediate value or sub-range within the given range, and all such intermediate values and sub-ranges are individually and specifically disclosed. For example, inter-well distances in a SAGD well pair are typically on the order of 5 m, however, this distance may vary, for example over a range of from about 3 to about 8 m, and the recital herein of a range from 3 to 8 m is accordingly understood to include any intermediate value or sub-range within 3 to 8 m.

Microorganisms.

The one or more microorganism described herein may be a bacterium or mixture of bacteria. The bacteria may, for example, be a mixture of anaerobic and aerobic bacteria capable of metabolizing hydrocarbon heavy ends of C16 or greater, or of C20 or greater. The mixture may be one that is similar to or the same as the mixture used in the lab testing phase described herein: BC-10 Bacteria™ (BioConcepts Inc. of Kemah, Tex.) optionally together with a catalyst or activator such as DHC50™, DHC-S50™, DHC-29™, DHA-9™, all available from BioConcepts, Inc. (Kemah, Tex.) which are selected for the ability to metabolize C16 and larger hydrocarbon materials existing in oil. The mixture of bacteria digest the hydrocarbon, thereby reducing the length of the molecule and producing by-products which can act as surfactants. This process lightens the heavy ends.

Optionally, one or more other additional strains of bacteria may be used be in inoculation step to metabolize the light ends of the hydrocarbon phase (in addition to metabolizing the heavy ends). Specifically, such additional strains of bacteria would be ones capable of metabolizing a hydrocarbon fraction having hydrocarbon molecules of 20 carbons or fewer. However, the ability to metabolize heavy ends (or in some embodiments, the preferential use of heavy ends as substrate) carries the advantage that the recovered oil becomes lighter and of a higher quality for later use. Typically, microorganisms capable of metabolizing light ends are used in recovery or remediation following downstream processing, for example in remediation of tailings ponds where heavy ends are unlikely to be located. An inoculant microorganism that would metabolize light ends would have the effect of, on balance, increasing the ratio of heavy to light ends, and may not have the observed effect on API and density.

An exemplary mixture, having 12 strains of anaerobic and anaerobic bacteria have the ability to metabolize carbon chains from about C16 to about C58. The inoculant bacterial mixture has a life span of approximately 6 to 8 weeks. Without being limited to theory, the products formed in the bacterial digestion process not only possess reduced reduce hydrocarbon chain length but also may act as surfactants and solvents, helping to mobilize the oil.

Microbial Products.

The microbial culture will produce smaller/lighter hydrocarbons from longer (C20 and greater) heavy ends, thus, resulting in an increased overall fluid mobility. Other microbial byproducts may act as surfactants that can advantageously help to mobilize oil adhered to the formation within the near-wellbore region. Further, gases such as H2 and methane which may be produced as a result of microbial metabolism of heavy ends may also contribute to overall fluid mobility by decreasing the viscosity and density of the oil in the near wellbore region. An increase in API, (as a parameter indicative of increased fluid mobility) is an exemplary parameter that can be used to evaluate the outcome of the method.

Before, after and in Lieu of Other Thermal Processes.

The inoculation with the bacterial mixture and subsequent increase in overall fluid mobility may act to precondition a reservoir prior to conducting thermal recovery processes, such as steam-assisted gravity drainage (SAGD) or cyclic steam stimulation (CSS), so as to accelerate start-up of a well. Optionally, a well that has completed the economic production using a thermal recovery process, such as SAGD or CSS, may be further exposed to the process described herein, so that inoculation after the thermal recovery process can result in further production of residual hydrocarbon remaining in the near wellbore region, such as the inter-well region when a well pair is utilized in SAGD. By utilizing the instant process when other thermal processes, such as SAGD or CSS, become less economical (due, in part, to the cost of steam production) recovery from a well after the final cycle of SAGD is completed (or “blowdown”) or after CSS is completed, recovery can be enhanced.

Further, the method described herein can result in such an increase in fluid mobility (and reduction in viscosity) that the method may be employed in place of a thermal recovery method such as SAGD or CSS, in wells that would otherwise be suitable for production through a thermal recovery process. The economics of production may be a parameter used to evaluate the efficiency of using the current method in lieu of other thermal processes, such as SAGD or CSS. In secondary pay zones which may have been conductively heated, but which still may require some additional fluid mobility to enhance recovery, the method described herein may be utilized with a secondary pay well to enhance the fluid mobility.

Circulation and Re-Inoculation.

Circulation or re-circulation of an inoculant solution may occur in certain embodiments provided herein. Advantageously, circulation may allow better colonization of the near-wellbore region, and/or increased exposure of the one or more microorganism to the available substrate. Once the microorganism has exhausted substrate supply in its immediate vicinity, a circulation of the inoculant solution helps to re-position microbes and encourages colonization in near-wellbore regions that may have be inaccessible at the initial inoculation. In order to circulate or re-circulate microorganisms, inoculant solution may be recovered or withdrawn from a well, such as the first or second well, for example by means of a pump. All or any portion of the initial microorganisms may be recovered, and subsequently re-injected into the near-wellbore region. Subsequent cycles of withdrawal/recovery and re-inoculation/insertion may be undertaken. Fresh inoculant solution and/or new microorganisms may be included at any stage in the circulation or re-circulation to the near-wellbore region.

Such circulation and re-circulation steps permit the one or more microorganism to mobilize and gain increased exposure to substrate (heavy ends) within the near wellbore region. Optionally, circulation and re-circulation of inoculant solutions may comprise delivery of a subsequent fresh solution of inoculant in place of the solution withdrawn, in situations where a change is deemed necessary. Further, the removal, or suctioning out, of original inoculant solution so as to circulate existing inoculant is also envisioned in certain embodiments, with or without fresh inoculant.

As a further alternative embodiment, additional microorganisms (and fresh inoculant solution) may be inoculated into the near-wellbore regions without withdrawal or removal of the initial inoculant, so as to increase pressure within the desired region of an oil sands reservoir. Such a re-inoculation step may be a one-time-only occurrence, or may occur periodically. In this embodiment, the surface to microorganism contact may increase by causing enhanced penetration of the near wellbore region. Inoculant solution may be withdrawn in small amounts and re-injected in the same or greater amounts through a pulsed timing. Such an embodiment can cause mixing of existing colonized microorganisms with fresh inoculant within the near-wellbore region. By pumping subsequent inoculant into a near-wellbore region, the previously injected microorganism solution is effectively pressured further into the oil sands reservoir, so as to further penetrate the region and access additional heavy end hydrocarbon substrate.

Pumping or re-inoculation can occur periodically, for example, once daily, once every second day, once per week, or by-weekly, as needed. The periodicity with which pumping/pulsing or re-inoculation is undertaken can be determined based on a leveling-off of the observed change in a fluid mobility parameter, such as viscosity or API, in a given near-wellbore region. Some reservoirs may benefit from more frequent periods if the change in fluid mobility occurs rapidly but then subsequent changes level off quickly.

An exemplary circulation volume of inoculant solution may be about 3× or more the volume of the standard horizontal section of the well. Thus, a section having a volume of 12 m3 would soak in a total volume per treatment from 36-40 m3 in such an embodiment.

The recirculation can be adjusted depending on whether the expected injectivity is reached or not. For example, it may be that both production and injector wells are inoculated (or either one or other of the producer or the injector well). When injecting one well, the first injection of 12-20 m3 of inoculant could be permitted a 2-3 week soaking period. Optionally, after the initial soaking period, additional fluid may be pumped into the well so that a total approximately 3-fold (fluid volume of up to about 36-40 m3) could be injected so as to squeeze the fluid into the near-wellbore regions. Such an option could be conducted by applying higher pressure into the reservoir with N2 gas in order to move the injected fluids further in, to permit soaking in. A subsequent soaking period of 2 to 3 weeks may be utilized. If the expected injectivity is not yet reached, the inoculant fluid may optionally be withdrawn and recirculated.

For situations in which the injector and producer wells are both inoculated, an exemplary injection of 12 m3 (based on volume of a standard horizontal section of a well) is provided to each well and permitted a soaking period, for example of 2-3 weeks. Following this, additional fluid may be added to squeeze the fluid and thus the microorganisms further into the reservoir. Optionally with N2 gas may be used. The total inoculant volume may be, for example about 40 m3 in total. Following this addition of fluid, a subsequent soaking period may ensue. Recirculation of the fluid may optionally be undertaken if the desired injectivity is not reached.

The initial injection and/or subsequent injections may occur by injecting into both injector and producer wells, or by selecting either the producer well or injector well. Regardless of the strategy selected, an exemplary target volume of about 3× a horizontal well section may be used.

In some embodiments, fluid remaining in a wellbore after the soaking period may be removed, for example by aspiration or pumping, and is subsequently then pumping back in to re-circulate, so as to permit better movement into and colonization of the wellbore. Further, such re-circulation may be conducted concomitantly with the addition of additional volumes of inoculant, for example to achieve a 3× fluid volume, which in some instances may be a 36-40 m3 volume of fluid per treatment. The fluid remaining in the wellbore after the soaking period can be either be recirculated or not. The desired or expected injectivity can be observed to inform the desirability of this option.

Time Periods.

After an appropriate period of time for the microbe or microbe mixture to contact and colonize a near-wellbore region, which may for example be an inter-well region, for example a period of about 5 days or more, such as about 10 days or more, 2 weeks or more, or 3 weeks or more, a highly saturated hydrocarbon phase will become less viscous, and less saturated due to the metabolism of the mixed microbial culture.

In an optional embodiment, following an initial soaking period of from about 2 to about 3 weeks, an additional volume of inoculant may be added to the near-wellbore region in order to increase pressure, and effectively squeeze the inoculant and attendant microorganisms further into the oil sands reservoir. In this way, additional contact is made between hydrocarbon substrate and the microorganisms.

Inoculant Composition.

Microorganism may be delivered within microbial culture, together with an appropriate carrier fluid that is water-based. The carrier fluid is one that does not impede microorganism viability, and which contains an appropriate balance of salts and/or nutrients as would be understood by a skilled person. Additional components can be included in the inoculant composition. For example, solvents may be added. Components which may be desirable to include within the well can be included in the inoculant composition. For example, downhole activators, downhole catalysts, solvents, surfactants, or buffers may be included in the inoculant composition. These components may assist in the delivery and colonization of the one or more microorganism; may help contribute (even in a minor way), to an increase in the water saturation (aqueous phase increase) of the near wellbore region thereby further facilitating the later mobility of steam through the formation when SAGD is subsequently undertaken, but need not play a specific role in effecting overall fluid mobility. Provided an additive to the inoculant composition does not greatly impede the overall increase in fluid mobility in a near-wellbore region, or kill the vast majority of the microorganisms, it may be included in the composition.

Exemplary quantities of solvent, when present (such as an organic solvent), relative to the mixture of microorganisms may be from about 5% to about 60% solvent. For example, from about 10% solvent to 50% solvent may be used. In some embodiments, 20% solvent or 30% solvent may be employed.

Accelerated Start-Up.

An advantage realized in certain embodiments provided herein is that time to start-up of a well for production can be reduced, thus accelerating start-up of a well for later SAGD production. For example, a typical start-up time with steam alone may be 3 months, while embodiments of the method described herein may accomplish start-up of a well into production in 4 to 6 weeks. Accelerated start-up time is desirable to more economically extract entrained oil from oil sand in the near-wellbore region. Steam will impact the viability of the microorganisms colonized in the near-wellbore region. Thus once SAGD begins, the impact on fluid mobility attributable to the microorganisms is lessened over time. The conversion of heavy ends to lighter (shorter) hydrocarbons due to metabolism by the microorganisms will have an initial effect in SAGD, in that fluid mobility of the oil produced will be enhanced.

Inoculation after SAGD or Other Recovery Process is Completed.

Steam-related oil recovery processes will result in a reduction of most, if not all, of the colonized microorganisms within a near-wellbore region. However, once the final cycle of a recovery process, such as SAGD cycle or CSS, is completed, a further inoculation could be employed to re-colonize the region and recover residual hydrocarbon.

During the “blowdown” period of SAGD, bitumen production continues with operations maintained under the same control scheme employed in conventional SAGD operations. Bitumen production rates decline over time as the growth rate of the steam front slows under gas injection. Production operations may continue until bitumen production declines to an uneconomic rate, at which time approximately 65% of the producible oil is projected to have been removed. Microbial inoculation according to the method described herein can be used at this stage to help with the mobility of the remaining oil, as thereby considerably decrease oil viscosity to an additional extent (and maximize recovery) at the point when steam and gas injection become uneconomic.

Embodiments in which a near-wellbore region is inoculated after the final SAGD cycle with the one or more microorganisms, can serve to maximize recovery of some of the remaining oil in an oil sands reservoir, when the use of steam becomes uneconomical. The near-wellbore region into which an inoculant solution is provided, after conventional SAGD production, has both a hydrocarbon phase and an aqueous phase, although much of the hydrocarbon has already been removed in SAGD. The viscosity of the hydrocarbon phase is nevertheless greater than the viscosity of the aqueous phase, and thus the method of increasing overall fluid mobility, as described herein, can assist in further hydrocarbon removal.

In certain SAGD operations, horizontal wells pairs may be drilled with one well disposed above the other. Multiple well pairs may be drilled from a single well pad, and over time, a pocket of unrecovered bitumen may forms in the space between two well pairs. Optionally Wedge Well™ technology allows access the wedge of bitumen via a single horizontal well drilled between two SAGD well pairs and pumping the oil to the surface through this additional well. The process described herein may be used before, after, or in lieu of Wedge Well™ technology.

Conditions Under which Microorganisms are Maintained.

Maintaining favorable conditions in the near-wellbore region allows the one or more microorganism to remain viable, and/or to propagate. The conditions permit the microorganism to survive and colonize in the near-wellbore region, and to metabolize the heavy ends as an energetic substrate. Such conditions may pertain to temperature, the presence of additives or solvent in an inoculant solution (or separately added to a reservoir), substrate within an inoculant, and other parameters.

Well bore conditions pertaining to start-up in a SAGD operation permit the one or more microorganism to remain viable in the near-wellbore region. Non-aqueous solvents may be included in the inoculant solution, or added separately to the near-wellbore regions, in modest amounts that do not affect microorganism viability. For example, a hydrocarbon solvent such as ethane, propane, or butane or larger alkanes (and mixtures of these) may be included. Aromatic solvents, such as xylene, benzene, toluene, phenol, or mixtures of these may be employed, as described in Canadian Patent No. 2,698,898, herein incorporated by reference in its entirety.

Inoculant is added under conditions that are sub-fracturing conditions (pressure or injection rate or both), and at an ambient temperature that permits survival of the microorganisms. Under colder seasonal climate conditions, care can be taken to ensure that the microorganism inoculant solution is not frozen, but is maintained for injection at a temperature that reasonably permits viability to be maintained. No heating is required for inoculation of the near-wellbore region, provided the inoculant is protected from excessively cold ambient climate temperatures prior to inoculating.

Gas may be included in the conditions of the near-wellbore region, such as air, oxygen, and nitrogen, provided the gas does not exclude the level of oxygen necessary for survival of aerobic bacteria.

The conditions may be designed to permit the inoculated microorganism to soak into the near-wellbore region for a period of time so as to displace, colonize, and interact with (metabolize) substrate within the near-wellbore region. A typical candidate oil sands reservoir may be one in which the bitumen or heavy oil density is about 15° API or heavier, such as 12°API or heavier. An exemplary gravity of 8-10° API may be found in the oil sands reservoir within which the near-wellbore regions is located.

SAGD Start-Up and Optional Conditions.

By way of comparison, standard conditions for SAGD (steam) start-up (not involving the inoculating and colonization by microorganisms, as described herein) may involve well pairs into which steam is injected in an amount of about 200 ton/day, with an injector bottom-hole pressure (BHP) of about 5 MPa, and a producer BHP of about 4.8 MPa, which is well below a typical fracture pressure. The startup stage of SAGD establishes communication between injection and production wells. An average start-up time for SAGD start-up may be about 90 days, and the amount of steam utilized for start-up may be in the range of about 20,000 m3. Initial reservoir conditions typically show negligible fluid mobility due to high oil viscosity and lack of water saturated zones in the inter-well region. SAGD start-up using steam can be supplemented, accelerated or replaced with the method described herein in which fluid mobility is increased using microorganism inoculation and colonization of the inter-well region.

Further optional conditions which may be employed in start-up, either before or after inoculation are described in Canadian Patent Application No. 2,757,125, the entirety of which is hereby incorporated by reference. Methods for steam-related oil recovery from an oil sand reservoir are described in this document. As well, the document teaches conditions under which fluid communication may be established between a well pair in an oil-sand reservoir having a dilatable inter-well region. Steam or water may be circulated within one or both wells of a well pair, to apply sufficient pressure to dilate the oil sands in the inter-well region. In this way, steam or water dilation may be employed to enhance fluid communication between the well pair. Such a method may be employed in concert with the method described herein for increasing overall fluid mobility.

An Embodiment, In Practice

Exemplary procedures which may be used in the field for SAGD wells may include the following details. It is to be understood that the procedure need not be limited to these exemplary embodiments.

Treatment with one or more microorganism, as described herein, may occur by placing an inoculant solution containing the microorganism into placed in one or both of the injector or producer SAGD wells. Varying durations of time may be employed to allow for the solution to soak into the formation and decrease bitumen viscosity. The optimal time required for soaking in may depend on characteristics of the oil sands reservoir in the region.

A mixture of microorganisms may be used, such as the 12 strain mixture, noted above, containing aerobic and anaerobic bacteria that have been selected to degrade the heavy ends (C16 hydrocarbons or greater) of the bitumen. In some embodiments, although not wishing to be limited by theory, the microorganisms may produce byproducts that act as bio-surfactants and solvents. Gases may also be produced. The bacteria can colonize a portion of, or the entire near-wellbore region, while metabolizing the heavy ends of hydrocarbon as food source. The bacterial culture can stay viable for is 6-8 weeks. Strains that can last for shorter or longer periods of time may be employed. The microorganisms may optionally be designed not to reproduce, or to have reduced viability following a set period of, for example 6-8 weeks.

To prepare the wells for the SAGD stage, and achieve communication where there is lack of injectivity, the inoculant solution can be pumped into both the injector and producer wells, or only into one of the injector or the producer well. If it is decided to inoculate both injector and producer wells, an exemplary amount of about 12 m3 of fluid may be included in each well. If it is decided to inoculate only one well, an initial volume 20 m3 can be pumped into the well.

After a soaking period of 2-3 weeks, the microbial solution may be recirculated in order to induce the microorganisms to keep moving and colonizing along the wellbore. Optionally, additional volumes of inoculant solution can be injected into the wellbore in order to squeeze the rest of the microorganisms further into the reservoir. The additional volume would then be permitted a further soaking of about 2-3 more weeks. Estimated total volumes to be injected in this example would be about 36-40 m3, or 2× to 3× the initial volume of inoculant solution.

Wells may be tested for communication utilizing steam injection into the injector well. If communication is achieved between well pairs, normal SAGD operations may then commence. As microorganisms typically die in temperatures higher than 95° C., the start of SAGD ends the role of the inoculant microorganisms. However, subsequent re-inoculation cycles may occur.

In the event that communication is not achieved, an alternative, such as dilation or steam circulation start up methodologies may also be considered.

EXAMPLES Example 1 Simulation Single Well Overview of Example 1

Two sets of simulations were performed to illustrate the effect of water saturation on start-up steam mobility Steam injection was simulated through the producer and no injector was simulated. A homogeneous model with live oil (15% wt methane) was used in the simulation. The producer completion was modelled after a standard SAGD well. A steam injection rate of 240 t/d was maintained until a cumulative injection volume of 3000 t was achieved (12.5 d).

In the first set of simulations, bottom-water was used to provide the reservoir with a mechanism for water displacement. The minimum water saturation for which a flow rate of 240 t/d could be sustained was Sw=25%. Maximum wellhead pressures for the system at the limiting water saturation were approximately 5422 kPag in the casing and 6400 kPag in the tubing. The tubing pressure at the wellhead corresponds to the maximum allowable wellhead pressure. Maximum down-hole pressure in both the tubing and casing were near 6400 kPag suggesting that at a saturation of Sw=25% a large pressure gradient must exist in order to push steam from the well, through the transition zone and into the bottom-water. It should be noted that this maximum steam pressure need only be maintained for a short time (roughly 1 d) until the mobility of the water in the reservoir improves.

In the second set of simulations, a water-rich zone at equal elevation to the pay zone was used to provide a mechanism for water displacement. The minimum water saturation for which a flow rate of 240 t/d could be sustained was Sw=37%. Wellhead pressures for the system (at transition zone Sw=37%) reached a maximum of 5500 kPag and 6400 kPag for the casing and tubing, respectively. Down-hole pressure was approximately 4500 kPag in the casing and 4800-4700 kPag in the tubing.

In both simulations, the minimum water saturation was the saturation at which the wellhead pressure reached the constraint of 6400 kPag (or 6500 kPag absolute). The higher minimum water saturation for the second set of simulations (with mobile water located at equal elevation to the reservoir) is due to the shorter and wider transition zone.

Details of Experimental Example 1

An objective of this Example was to determine the lowest possible water saturation which allows for steam injectivity of 240 t/d per well pair and a cumulative steam injection of 3000 t during well start-up. Two geometries were considered in this Example. The first consisted of a homogeneous live-oil reservoir with bottom-water. The second consisted of an identical reservoir, but with the bottom-water replaced by an infinitely large water-rich region at the same depth as the pay zone.

In both simulations, the reservoir dynamics as well as the wellbore dynamics in the horizontal and build sections were simulated. A summary of the reservoir properties and conditions is listed in Table 1 below. The wellbore was modelled using a standard completion approach to SAGD in an oil sands reservoir.

TABLE 1 Reservoir Properties Property Value Units Initial Temperature 12 ° C. Initial Pressure 3000 kPa Methane in Oil 15 Mol % Ka (x/y/z) 4/4/2 Darcies Initial Oil Saturation 80 % Initial Water Saturation 20 % Porosity 0.35 Width/Length/Height 50/732/20 m

Simulation details are as follows: casing, tubing and ports were all included in the simulation. The Bubble tube was not included in the simulation as it has minimal effect of the flow dynamics. The port was simulated using a compressible port model. Heat loss around the reservoir and build section was simulated using a shale property model. It should be noted that half-geometry models were used for the reservoir. As a result, the simulation stopped when (3000/2=) 1500 t were injected. Also, the in-simulation rate of injection was half of the 240 t/d specified for this problem.

The infinitely-large water region was simulated using a water-rich region (Sw=100%) containing several production sources. The pressure of these production sources was kept at 3000 kPa. This allowed mobile fluids at pressures greater than 3000 kPa to be removed from the system.

Two geometries were considered in Example 1. A geometry for the bottom water simulations and a geometry for the side-water simulations.

Bottom-Water Simulations.

The first set of simulations was proposed for the geometry illustrated in FIG. 1 herein. Under this geometry, a homogeneous rectangular reservoir of live oil was bounded on three sides by a shale heat-loss grid and underneath by bottom-water (Sw=100%). In addition the bottom 2 m of the reservoir contained a transition zone with 50%>Sw>20%. The producer well (which was operated as a steam injection well) was placed in the middle of the transition zone (i.e., 1 m above the bottom-water).

The simulations were run until a cumulative injection mass of 3000 t (1500 t in-simulation due to half-geometry) was achieved. The injection rate was 240 t/d (120 t/d in-simulation due to half-geometry). At a water saturation of 25% it was found that an injection rate of 240 t/d was sustainable. However, at a water saturation of 22%, it was found that the injection rate of 240 t/d was not sustainable. As a result, the predicted minimum water saturation is between 25% and 22%. A value of 25% is reported in this work because it is the lowest value for which a rate of 240 t/d was successfully sustained.

In order to inject 3000 t of steam at 240 t/d the simulation had to be run for at least 12.5 d. Wellhead pressure as a function of time for the first 12.5 d of simulation is shown in FIG. 1. As shown in FIG. 2, the maximum injection pressure was attained early in the simulation (after roughly 1 d). As the simulation progressed, the wellhead pressure decreased considerably. This is likely due to the effect of steam in improving the mobility of water in the reservoir. Specifically, it is likely that the increased mobility is due to viscosity reduction associated with temperature rise due to steam penetration and condensation in the reservoir.

Casing and tubing pressure for the bottom-water system, after 12.5 d, as a function of distance from surface is shown in FIG. 2 herein. As can be seen from FIG. 3, the pressures in the horizontal section of the well are in-line with typical operating pressures. This suggests that once a high rate of steam injection is obtained it can be maintained.

Side-Water Simulations.

A second set of simulations was proposed for a side-water system geometry illustrated in FIG. 4 herein. Under this geometry, a homogeneous rectangular reservoir of live oil was bounded on four sides by a shale heat-loss grid and to the side by mobile water (Sw=100%). As with the geometry described in the bottom-water section above, the bottom 2 m of the reservoir contained a transition zone with 50%>Sw>20%. The producer well (which was operated as a steam injection well) was placed in the middle of the transition zone (i.e., 1 m above the bottom-water). The distance of transition zone between the side-water and the producer was 49.5 m.

The simulations were run until a cumulative injection mass of 3000 t (1500 t in-simulation due to half-geometry) was achieved. The injection rate was 240 t/d (120 t/d in-simulation due to half-geometry). At a water saturation of 37% it was found that an injection rate of 240 t/d was sustainable. However, at a water saturation of 35%, it was found that the injection rate of 240 t/d was not sustainable. As a result, the predicted minimum water saturation is between 35% and 37%. A value of 37% is reported in this work because it is the lowest value for which a rate of 240 t/d was successfully sustained.

In order to inject 3000 t of steam at 240 t/d the simulation had to be run for at least 12.5 d. Wellhead pressure as a function of time for the first 12.5 d of simulation is shown in FIG. 3 herein. As shown in FIG. 5, the pressure dynamics for the side-water system are qualitatively different than the dynamics for the bottom-water system. In the side-water system the wellhead pressure starts low and builds up over time. While the rate of 240 t/d can be sustained, it is at the price of ever increasing wellhead pressure; as such, it is less likely that this injection rate can be maintained past 12.5 d. Unlike the bottom-water system, the dynamic whereby steam increases water mobility and allows for flow at lower pressures is not present. This may be due to the long path the injection fluid must take in order to reach the mobile water and the associated heat.

Casing and tubing pressure, for the side-water system, after 12.5 d, as a function of distance from surface is shown in FIG. 6. As can be seen from FIG. 6, the entire horizontal well section is nearly at the maximum wellhead pressure. This suggests that the flow in this system is hindered (and is limited) by the distance and cross-sectional area of transition zone channel to the mobile water.

From the simulations of the bottom- and side-water systems it appears that at the minimum water saturation, the system is constrained by the wellhead pressure. It is useful, therefore to examine the relationship between wellhead pressure and water saturation. To do this, both geometries were simulated using Sw values of 50, 45 40 and 37%. The bottom-water system was additionally simulated at Sw values of 35, 30, and 25%. The maximum tubing wellhead pressure for each simulation as a function of water saturation is shown in FIG. 5 herein.

As can be seen from FIG. 7, the geometry of the bottom-water simulation (characterized by a wider and shorter transition zone) implies that, at a given saturation, less pressure is required to drive a fixed amount of steam into the reservoir. The proximity of mobile water is therefore critical in determining the minimum water saturation at which steam can be injected into the reservoir.

Conclusions for Example 1

The two foregoing simulations were performed in order to exemplify the effect of water saturation on the ability of a reservoir to accept steam at a rate of 240 t/d. The first set of simulations corresponded to a system geometry with bottom-water and a 2 m transition zone with 1 m between the well and the bottom-water. For this set of simulations, the simulation data results reasonably predict that one can inject steam for transition zone water saturations as low as 25%. This saturation corresponded to the constraint well head pressure of 6400 kPag. The second set of simulations corresponded to a geometry with side-water and a 2 m (width)×50 m (length) transition zone with the well being positioned 49.5 m from the mobile water. For this set of simulations, the simulation data results reasonably predict that steam can be injected for transition zone water saturations as low as 37%. This saturation corresponds to the constraint well head pressure of 6400 kPag.

Example 2 Simulation Two Well System Overview of Example 2

A single set of simulations were performed to illustrate the effect of water saturation on start-up steam mobility for a generic well pair. Steam injection was simulated from an injector to a producer well. A homogenous model with live oil (15% wt methane) was used in this simulation. The injector and producer completions were modelled after a standard SAGD well pair. The injection wellhead pressure was maintained at 8000 kPa. A maximum pressure differential of 7000 kPa was maintained between the injector and producer wells.

A water saturation of Sw=25% was found to allow steam to be injected into the injector at a sustained rate of at least 240 t/d after about 13 days. The maximum well head pressure at this water saturation was approximately 8000 kPag. It should be noted that the maximum steam pressure differential of 7000 kPa need only be maintained for 18 days until the mobility of the fluid in the reservoir improves.

Details of the Experimental Example 2

An objective of this Example was to illustrate that a saturation of Sw=25% was sufficient to allow for a steam injectivity of 240 t/d per well pair in a relatively short period of time (around about 12 days).

In these well pair simulations, the reservoir dynamics as well as the well bore dynamics were simulated. A summary of reservoir properties and conditions is provided in Table 1 above. The well bores were modelled using a standard completion approach in a SAGD well pair.

Simulation details are as follows: casing, tubing and ports were all included in the simulation. The Bubble tube was not included in the simulation as it has minimal effect on the flow dynamics. The port was simulated using a compressible port model. Heat loss around the reservoir and injector build section was simulated using a shale property model. The simulation was run for 40 days. It should be noted that this is longer than the time necessary to achieve a rate of 240 t/d of steam injection.

The geometry for the two-well simulations is shown in FIG. 8 herein. Under this geometry, the homogeneous rectangular reservoir of live oil was bounded on four sides (top, bottom, heel, and toe) by shale heat loss grids. The area to the left and right of the reservoir was not connected to a heat loss grid in order to allow for half symmetry. The reservoir was modelled with a 20 m pay thickness and was 732 m in length. A typical inter-well spacing of 100 m was assumed. The producer was placed at the bottom of the pay zone. The injector was placed, using a typical inter-well spacing of 5 m, above the producer.

Tubing (or injection) wellhead pressure was maintained at 8000 kPa for this simulation. Casing wellhead pressure as a function of time for all 40 days of simulation is illustrated in FIG. 9. As shown in FIG. 9, there is little drop in the casing wellhead pressure from 2 to 20 days. As the simulation progressed past about 20 days, the casing wellhead pressure decreased considerably. This is likely due to the increased mobility of fluids in the reservoir related to steam injection. Specifically, it is likely that the increased mobility is due to viscosity reduction associated with temperature rise related to steam penetration and condensation in the reservoir.

Casing and tubing pressure for the two-well system, after 40 days as a function of distance along the horizontal section of the well for both the injector and producer are shown in FIG. 10 herein. As can be seen from FIG. 10, the pressure in the horizontal section of the casing is in line with typical operating pressures. This suggests that once a high rate of steam injection is obtained, it can be maintained.

Conclusions for Example 2

The foregoing simulations were performed in order to exemplify the effect of water saturation on the time taken to establish communication between a well pair. This set of simulations corresponds to a system geometry as illustrated in FIG. 7 and having the properties shown in Table 1. For this set of simulations the simulation data reasonably predicts, that if the initial inter-well water saturation is Sw=25%, one can establish inter well communication with a saturated steam injection rate of 240 t/d at 8000 kPa well head pressure after the end of 12 days.

Example 3 Lab Testing Overview of Example 3

Static tests were conducted in the lab in order to verify the effectiveness of a bacterial culture in increasing the mobility of fluid in the reservoir. Tests were conducted using a mixture of bacteria capable of metabolizing heavy ends of C20 or greater from a hydrocarbon phase. In this example mobility parameters of the resulting fluids were studied in a lab scale reservoir.

Details of the Experimental Example 3

Two tests were conducted in the lab in order to verify the effectiveness of a mixed bacterial culture in upon the mobility of fluids in a laboratory reservoir.

Two samples of 200 g reservoir sand that was highly saturated with oil were used and completed with 700 ml of a bacterial solution at different concentrations in two different containers. This solution contained an aqueous bacterial mixture (70%) and organic solvents (30%). The bacterial mixture contained a microbial mixture of BC-10 Bacteria™ (BioConcepts, Inc., Kemah, Tex.), a mixture of 12 strains of anaerobic and aerobic bacteria, having the ability to metabolize heavy ends, or hydrocarbons of C16 or greater.

In a separate test, a sample with 400 g of reservoir sand and 400 ml of bacterial solution having the same composition as above, was tested in order to evaluate the sand/microbial solution relationship to estimate the volume of solution that will be required to inoculate the well.

The tests were conducted at room temperature. Wells were inoculated with the bacterial mixture, and maintained at room temperature under conditions adequate for viability and propagation of the bacteria. After 24 to 48 hours of exposure, the oil started to separate and mobilize from the sand, and sit on top of the samples. After a two week soaking period, most of the oil in the sand became mobilized.

The total oil recovered from the samples was measured. For this test, the total oil recovered was quantified and compared to the original volume of oil in the original sand.

Table 2 shows the initial sample properties and properties of the oil observed in one of the 200 g test samples. The designation of crude oils based on density may be evaluated with API (American Petroleum Institute) gravity, a common measure of the density of liquid petroleum, measured in degrees.

TABLE 2 Sample Properties and Initial Oil Properties Property Value Units Temperature 18 (room conditions) ° C. Initial Oil Content 90 % Initial Water Content 10 % Porosity 0.35 % API 8-10 Degrees Viscosity 122,333 cP Density 1.0076 g/cc Oil volume in sample 27.19 ml Sample volume 200 g Microbial solution volume 700 ml

Results for Example 3

After two weeks of a soaking period, the 200 g samples were analyzed in the lab in order to measure the recovered oil new properties and evaluate its effectiveness. It was observed that most of the oil mobilized to the top of the sample. The amount of oil recovered was quantified and the sand was tested using Dean-Stark method to measure the remaining oil fraction in the sample. Results were then compared to the original volume of oil in the original sand in order to evaluate the properties of the recovered oil and evaluate effectiveness.

The 400 g samples were analyzed after a 23 day soaking period. Oil also mobilized on top of the jars, and the properties of the recovered were evaluated following the methodology noted above for comparison with the original properties and volume of oil in the original sample.

The properties of the sample following lab scale microbial treatment of the 200 g samples show that, at room temperature (18° C.), initial oil content was 90%, while initial water content was 10%. Porosity was 0.35%. After microbial treatment API was about 27 degrees, viscosity was greatly reduced to about 1.7-1.9 cP, and density showed a change to the level of from about 0.887-0.890 g/cc. 14 g of total oil was recovered from one of the samples after 2 weeks of soaking. Additional data is shown in the tables below.

The results confirm that the microbial treatment using a mixture of bacteria capable of metabolizing heavy ends, resulted in a marked decrease in viscosity relative to the starting value of the solution. This dramatically impacted the mobility of the oil, increasing API from 8-10 to 27, and decreasing viscosity from about 122,300 cP to about 1.7-1.9 cP.

Notably, the two week laboratory scale process using the 200 g jars with 700 ml of bacterial solution, the total recovered oil was 44-49% of the original sample. This was a satisfactory result. As this was a static test, it is noted that the remaining oil in the sand could be mobile in the sand pores. The viscosity of the oil decreased from about 122,333 cP to about 1.7-1.9 cP, and the quality of the oil increased from 8-10 API to 27 API under room temperature conditions.

In the tests employing the 400 g sample mixed with 400 ml of microbial solution, the total recovered oil was about 21-40%. This test incorporates the assumption that there is mobile oil in the sand pores. The viscosity of the oil decreased from about 122,333 cP to about 5.4 cP, and the quality increased from 8-10 API to 21.8 API under room temperature conditions.

A comparison of the parameters indicative of or pertaining to overall fluid mobility before and after treatment of oil sand for the 200 g samples illustrates good efficacy. The oil content was reduced while the water content of the sample increased from about 10% to about 12%. Increased water saturation increases the mobility of fluid in the vicinity. Viscosity was greatly reduced from 122,333 to 1.7 cPs in one of the samples. The density change was also remarkable, starting at about 1002 g/cc in the original sample, and resulting in 0.877 g/cc following a 2 week microbial treatment. The API also increased from about 8-10 to about 27, indicative of a lightening of the oil, and an increase in fluid mobility attributable to a reduction in heavy ends following microorganism metabolism. Of the 27.19 mL of oil in one of the samples, about 14 mL of this was recovered. Further data is provided in the tables below.

Table 3 and Table 4 provide data pertaining to sample characteristics for both the 200 g samples and the 400 g samples as well as a control (uninoculated) sample.

TABLE 3 Density and Viscosity of Isolated Oil Fraction Density Density Bacteria:Sample Volume (15° C.) API Sample (g:mL) (mL) kg/m3 (15.6° C.) DPS Pre-treated 200:700 220 890.5 27.3 200 Solution A DPS Pre-treated 200:700 240 887 27.9 200 Solution B 200 Control 201:0  n/a n/a n/a 400 Control 404:0  n/a n/a n/a 400 Treatment A 400:400 120 924.4 21.5 400 Treatment B 400:400 120 922.5 21.8 Kinematic Viscosity Bacteria:Sample 20° C. 30° C. 40° C. Sample (g:mL) (cSt) (cSt) (cSt) DPS Pre-treated 200:700 2.163 1.827 1.574 200 Solution A DPS Pre-treated 200:700 1.944 1.651 1.425 200 Solution B 200 Control 201:0  n/a n/a n/a 400 Control 404:0  n/a n/a n/a 400 Treatment A 400:400 9.665 7.272 5.666 400 Treatment B 400:400 8.622 6.55 5.144 Dynamic Viscosity Bacteria:Sample 20° C. 30° C. 40° C. Sample (g:mL) (cP) (cP) (cP) DPS Pre-treated 200:700 1.919 1.607 1.372 200 Solution A DPS Pre-treated 200:700 1.717 1.445 1.237 200 Solution B 200 Control 201:0  n/a n/a n/a 400 Control 404:0  n/a n/a n/a 400 Treatment A 400:400 8.899 6.644 5.135 400 Treatment B 400:400 7.923 5.97 4.651

TABLE 4 Composition of Isolated Sand Fraction Mass Bacteria:Sample Sample Mass Dean-Stark Dean-Stark Sample (g:mL) Tested (g) Solids (g) Water (g) DPS Pre-treated 200:700 159.2 127.6 19.3 200 Solution A DPS Pre-treated 200:700 148.6 116.8 18.3 200 Solution B 200 Control 201:0  200.6 170.6 2.6 400 Control 404:0  404.9 339.3 3.8 400 Treatment A 400:400 462.2 355.2 72.9 400 Treatment B 400:400 456.8 351 61 Dean-Stark Fractions Oil Bacteria:Sample Solids Water (Wt. %) by Sample (g:mL) (Wt. %) (Wt. %) difference DPS Pre-treated 200:700 80.20% 12.10% 7.70% 200 Solution A DPS Pre-treated 200:700 78.60% 12.30% 9.10% 200 Solution B 200 Control 201:0  85.00% 1.30% 13.70% 400 Control 404:0  83.80% 0.90% 15.30% 400 Treatment A 400:400 76.80% 15.80% 7.40% 400 Treatment B 400:400 76.80% 13.40% 9.80% Recovery Estimated Oil Bacteria:Sample Remaining in Oil Recovered Sample (g:mL) Sand (mL) (mL) RF % DPS Pre-treated 200:700 13.81 13.38 49 200 Solution A DPS Pre-treated 200:700 15.22 11.97 44 200 Solution B 200 Control 201:0  27.19 n/a n/a 400 Control 404:0  61.33 n/a n/a 400 Treatment A 400:400 36.89 24.45 40 400 Treatment B 400:400 48.56 12.77 21

The following tables provide a side-by side comparison of results for the 200 g sample (Table 5) and the 400 g samples (Table 6). Notably, the two weeks laboratory scale process resulted in recovery of about 49% of the oil.

TABLE 5 Comparison Table before and After Treatment (200 g sample) Sample After Original Sample Microbial Treatment Property (Pre-treatment) (*2 weeks) Oil 90% (So ~7% *Estimated percentage estimated) of oil in the isolated sand fraction Water 10% (Initial Sw) ~12%*Estimated percentage of water in in the isolated sand fraction Oil Viscosity 122,333 cP 1.7 cP Oil Density 1,0076 g/cc 0.887 g/cc Oil API 8-10 27 Total oil recovered 27.19 ml 12-13 ml (44-49% from sample Recovered from sample oil)

TABLE 6 Side-by Side Comparison Table Before and After Treatment (400 g samples) Sample After Original Sample Microbial Treatment Property (Pre-treatment) (*2 weeks) Oil 90% (So 9.80% *Estimated percentage estimated) of oil in the isolated sand fraction Water 10% (Initial Sw) 13.40%*Estimated percentage of water in in the isolated sand fraction Oil Viscosity 122,333 cP 5.9 cP Oil Density 1,0076 g/cc 0.922 g/cc Oil API 8-10 22 Total oil recovered 61.33 ml 13-24 ml (21-40% from sample Recovered from sample oil)

Results of both tests establish the favorable impact that inoculation with microorganisms has on fluid mobility parameters. An exemplary field treatment with a microbial solution may employ a volume of the solution that is about 3-fold or more of the estimated volume for a standard horizontal section of the well. An exemplary estimated volume of 800 m of horizontal well section would be about 12 m3, and thus a volume of three times this would be about 36-40 m3.

Positive results from this microbial enhanced start-up illustrate that the method described herein for increasing overall fluid mobility in a near-wellbore region in an oil sands reservoir has the potential to optimize the recovery of oil from a reservoir in the same manner as can be realized using stream-based or solvent-based processes. Benefits of solvent utilization may include reduced emissions intensity, reduced water handling intensity, and reduced fuel gas consumption intensity (with “intensity” referring to per barrel of oil produced). Further, it is beneficial to have optional technologies to supplement or augment existing technologies used field recovery from oil sand, as such technologies can act be accessed when economic, environmental, or climate conditions render certain options less economical.

Conclusions for Example 3

The method described herein was effective at increasing overall fluid mobility in a laboratory scale version of a near-wellbore region in an oil sands reservoir. Oil phase (hydrocarbon phase) saturation decreased, while water saturation (aqueous phase) increased. Viscosity was greatly reduced, thereby increasing the flowability of the oil. The increase in API demonstrates that the heavy ends of the oil were metabolized, resulting in a lighter gravity. A commensurate change in density was observed. The recovery observed for this lab scale example serves to illustrate that this method may offer an alternative to SAGD, or may be used for wells after SAGD is completed, in an effort to recover residual oil when SAGD becomes less economical.

While specific embodiments have been described and illustrated, such embodiments should be considered illustrative only and not as limiting the invention as construed in accordance with the accompanying claims. Other features and advantages will be apparent from the following description, drawings and claims.

It will be understood that any singular form is intended to include plurals herein. For example, the word “a”, “an” or “the” is intended to mean “one or more” or “at least one.” Plural forms may also include a singular form unless the context clearly indicates otherwise.

It will be further understood that the term “comprise”, including any variation thereof, is intended to be open-ended and means “include, but not limited to,” unless otherwise specifically indicated to the contrary.

When a list of items is given herein with an “or” before the last item, any one of the listed items or any suitable combination of two or more of the listed items may be selected and used. For any list of possible elements or features provided in this specification, any sub-list falling within the given list is also intended.

The above described embodiments are intended to be illustrative only and in no way are to be construed as being limiting. The described embodiments are susceptible to many modifications of form, arrangement of parts, details and order of operation. All such modification are encompassed within the scope defined by the claims.

All citations are expressly incorporated herein in their entirety by reference.

Claims

1. A method of increasing overall fluid mobility in a near-wellbore region in an oil sands reservoir, the method comprising:

(a) inoculating the near-wellbore region with one or more microorganism, wherein the near-wellbore region comprises a hydrocarbon phase and an aqueous phase, the viscosity of the hydrocarbon phase being greater than the viscosity of the aqueous phase; and
(b) maintaining conditions in the near-wellbore region so that the one or more microorganism metabolizes at least a portion of the hydrocarbon phase so that saturation of the near-wellbore region by the hydrocarbon phase decreases and saturation of the near-wellbore region by the aqueous phase increases, increasing overall fluid mobility.

2. The method of claim 1, wherein the method increases the overall fluid mobility in an inter-well region between a first well and a second well of a well pair in the oil sands reservoir,

wherein the near-wellbore region is associated with at least one of the first and second well, and at least a portion of the near-wellbore region is within the inter-well region.

3. The method of claim 2, wherein the first well is an injection well and the second well is a production well.

4. The method of claim 3, wherein inoculating occurs prior to steam-assisted gravity drainage (SAGD) to pre-condition the oil sands reservoir for SAGD.

5. The method of claim 3, wherein inoculating occurs after steam assisted gravity drainage (SAGD) is completed.

6. The method of claim 2, wherein inoculating occurs instead of steam assisted gravity drainage (SAGD) in the oil sands reservoir, and wherein the method additionally includes the step of producing oil from the producing well.

7. The method of claim 2, wherein (b) comprises maintaining propagating conditions in at least a portion of the inter-well region so that the one or more microorganism propagates within the inter-well region.

8. The method of claim 7, wherein the propagating conditions comprise conditions in which the one or more microorganism metabolizes at least a portion of the hydrocarbon phase, decreasing saturation of the inter-well region by the hydrocarbon phase and increasing saturation of the inter-well region by the aqueous phase.

9. The method of claim 2, further comprising a cycling process comprising:

(c) injecting or circulating a heated cycling fluid within one or both of the first or second well in fluid communication with the near-wellbore region, to mobilize fluids within the near-wellbore region; and
(d) repeating steps (a) and (b) so that the one or more microorganism metabolizes a further portion of the hydrocarbon phase.

10. The method of claim 9, wherein the cycling process steps (c) and (d) are repeated one or more times.

11. The method of claim 10, wherein the cycling process steps are repeated for a period of about two weeks or greater.

12. The method of claim 1, wherein the one or more microorganism is contained in an inoculant solution, and:

following step (a) the inoculant solution is absorbed into the near-wellbore region over a soaking period, and after the soaking period additional inoculant solution is added into the near-wellbore region well to increase overall fluid mobility.

13. The method of claim 12 wherein unabsorbed inoculant solution is withdrawn from the near-wellbore region after the soaking period; and is combined with the additional inoculant solution for adding into the near-wellbore region, to re-circulate in the near-wellbore region.

14. The method of claim 13, wherein the total volume of inoculant solution in step (a) plus the additional inoculant solution is from about 2× to about 3× the volume of the volume of inoculant solution used in step (a).

15. The method of claim 9, wherein the heated cycling fluid comprises steam, water, a solvent, a surfactant, or a combination thereof.

16. The method of claim 1, wherein:

the saturation of the near-wellbore region by the aqueous phase increases by about 25% or greater; and/or
the saturation of the near-wellbore region by the hydrocarbon phase decreases by about 50% after about two weeks.

17. The method of claim 2, wherein fluid communication is established between the first well and the second well following step (a) and (b).

18. The method of claim 17, comprising injecting or circulating a fluid in: (i) the first well; (ii) the second well; or (iii) both the first well and the second well to establish the fluid communication between the first well and the second well.

19. The method of claim 1, further comprising:

determining a first saturation level of the aqueous phase in the near-wellbore region prior to inoculating, and determining a second saturation level of the aqueous phase in the near-wellbore region following inoculating, and optionally determining the increase in aqueous phase saturation; and/or
determining a first fluid mobility level of in the near-wellbore region prior to inoculating, and determining a second fluid mobility level in the near-wellbore region following inoculating, and optionally determining the increase in fluid mobility.

20. The method of claim 1, wherein the one or more microorganism metabolizes hydrocarbons of C16 or greater.

21. The method of claim 1, wherein the one or more microorganism preferentially metabolizes hydrocarbons of C20 or greater.

22. The method of claim 21, wherein the one or more microorganism comprises bacteria that preferentially metabolizes heavy ends of the oil in the oil sands reservoir.

23. The method of claim 3, further comprising a step of injecting a heated fluid into the injection well or circulating the heated fluid in the well pair prior to the step of inoculating.

24. The method of claim 2, wherein the wells in the well pair each have a section that extends substantially in a horizontal direction, and wherein fluid communication is established between the substantially horizontal sections.

25. The method of claim 24, wherein the substantially horizontal sections of the wells are substantially parallel, and vertically spaced apart.

26. The method of claim 1, additionally comprising circulating or re-circulating the one or more microorganism within the near-wellbore region to increase exposure of the one or more microorganism to hydrocarbons of C20 or greater.

27. A method of recovering hydrocarbon from in an inter-well region in an oil sands reservoir located between an injection well and a production well, the method comprising:

(a) inoculating the inter-well region with a mixture of anaerobic and aerobic bacteria that metabolizes hydrocarbons of C16 or greater;
(b) maintaining viability of at least a portion of the mixture of bacteria in the inter-well region so that the mixture of bacteria metabolizes at least a portion of the hydrocarbon phase having C16 or greater, to produce a hydrocarbon phase of decreased viscosity; and
(c) recovering the hydrocarbon phase of decreased viscosity from the inter-well region.

28. The method of claim 27, additionally comprising repeating steps (a) to (c).

29. The method of claim 27, wherein inoculating the inter-well region comprises injecting the mixture of bacteria into the injection well together with a suitable carrier.

30. A method of increasing overall fluid mobility of oil in a near-wellbore region in an oil sands reservoir, comprising:

inoculating a well with an inoculant solution comprising one or more microorganism that metabolizes hydrocarbon of C16 or greater;
permitting the inoculant solution to become absorbed into the near-wellbore region over a soaking period; and
adding additional inoculant solution into the well to increase overall fluid mobility of oil.

31. The method of claim 30, additionally comprising:

withdrawing unabsorbed inoculant solution after the soaking period; and
combining the withdrawn solution with the additional inoculant solution added into the well to re-circulate in the well.

32. The method of claim 30, wherein the total volume of inoculant solution used in the steps of inoculating and adding is at least about 3× the volume used in the step of inoculating.

33. The method of claim 30, wherein the soaking period is from about 2 to about 3 weeks.

Patent History
Publication number: 20140116682
Type: Application
Filed: Nov 1, 2013
Publication Date: May 1, 2014
Inventors: Rosana Patricia BRACHO DOMINGUEZ (Calgary), Amos BEN-ZVI (Calgary), Kirsten Amy Yeates PUGH (Calgary), Subodh GUPTA (Calgary)
Application Number: 14/070,095
Classifications
Current U.S. Class: Using Microorganisms (166/246)
International Classification: E21B 43/14 (20060101);