Patent Application
20130199777
This application claims the benefit of Canadian patent application number 2,766,844 filed on Feb. 6, 2012 entitled HEATING A HYDROCARBON RESERVOIR, the entirety of which is incorporated herein.
The present techniques relate to harvesting resources using gravity drainage based processes. Specifically, techniques are disclosed for lowering the viscosity of the resources within a reservoir in preparation for the implementation of a gravity drainage based process.
This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Modern society is greatly dependent on the use of hydrocarbons for fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface rock formations that can be termed “reservoirs.” Removing hydrocarbons from the reservoirs depends on numerous physical properties of the rock formations, such as the permeability of the rock containing the hydrocarbons, the ability of the hydrocarbons to flow through the rock formations, and the proportion of hydrocarbons present, among others.
Easily harvested sources of hydrocarbons are dwindling, leaving less accessible sources to satisfy future energy needs. However, as the costs of hydrocarbons increase, these less accessible sources become more economically attractive. For example, the harvesting of oil sands to remove hydrocarbons has become more extensive as it has become more economical. The hydrocarbons harvested from these reservoirs may have relatively high viscosities, for example, ranging from 8 API, or lower, to up to 20 API, or higher. Accordingly, the hydrocarbons may include heavy oils, bitumen, or other carbonaceous materials, collectively referred to herein as “heavy oil,” which are difficult to recover using standard techniques.
Several methods have been developed to remove hydrocarbons from oil sands. For example, strip or surface mining may be performed to access the oil sands, which can then be treated with hot water or steam to extract the oil. However, deeper formations may not be accessible using a strip mining approach. For these formations, a well can be drilled to the reservoir and steam, hot air, solvents, or combinations thereof, can be injected to release the hydrocarbons. The released hydrocarbons may then be collected by the injection well or by other wells and brought to the surface.
A number of techniques have been developed for harvesting heavy oil from subsurface formations using well-based recovery techniques. These operations include a suite of steam based in-situ thermal recovery techniques, such as cyclic steam stimulation (CSS), steam flooding and steam assisted gravity drainage (SAGD), as well as surface mining and their associated thermal based surface extraction techniques.
For example, CSS techniques include a number of enhanced recovery methods for harvesting heavy oil from formations that use steam heat to lower the viscosity of the heavy oil. These steam assisted hydrocarbon recovery methods are described in U.S. Pat. No. 3,292,702 to Boberg, and U.S. Pat. No. 3,739,852 to Woods, et al., among others. CSS and other steam flood techniques have been utilized worldwide, beginning in about 1956 with the utilization of CSS in the Mene Grande field in Venezuela and steam flood in the early 1960s in the Kern River field in California.
The CSS process may raise the steam injection pressure above the formation fracturing pressure to create fractures within the formation and enhance the surface area access of the steam to the heavy oil, although CSS may also be practiced at pressures that do not fracture the formation. The steam raises the temperature of the heavy oil during a heat soak phase, lowering the viscosity of the heavy oil. The injection well may then be used to produce heavy oil from the formation. The cycle is often repeated until the cost of injecting steam becomes uneconomical, for instance if the cost is higher than the money made from producing the heavy oil. However, successive steam injection cycles reenter earlier created fractures and, thus, the process becomes less efficient over time. CSS is generally practiced in vertical wells, but systems are operational in horizontal wells.
Solvents may be used in combination with steam in CSS processes, such as in mixtures with the steam or in alternate injections between steam injections. These techniques are described in U.S. Pat. No. 4,280,559 to Best, U.S. Pat. No. 4,519,454 to McMillen, and U.S. Pat. No. 4,697,642 to Vogel, among others.
Cyclic enhanced recovery techniques have been developed that are not based on thermal methods. For example, U.S. Pat. No. 6,769,486 to Lim, et al., discloses a cyclic solvent process for heavy oil production. In the process, a viscosity reducing hydrocarbon solvent is injected into a reservoir at a pressure sufficient to keep the hydrocarbon solvent in a liquid phase. The injection pressure may also be sufficient to cause dilation of the formation. The hydrocarbon solvent is allowed to mix with the heavy oil at the elevated pressure. The pressure in the reservoir can then be reduced to allow at least a portion of the hydrocarbon solvent to flash, providing a solvent gas drive to assist in removing the heavy oil from the reservoir. The cycles may be repeated as long as economical production is achieved.
Another group of techniques is based on a continuous injection of steam through a first well to lower the viscosity of heavy oils and a continuous production of the heavy oil from a lower-lying second well. Such techniques may be termed “steam assisted gravity drainage,” or SAGD. Various embodiments of the SAGD process are described in Canadian Patent No. 1,304,287 to Edmunds and U.S. Pat. No. 4,344,485 to Butler.
In SAGD, two horizontal wells are completed into the reservoir. The two wells are first drilled vertically to different depths within the reservoir. Thereafter, using directional drilling technology, the two wells are extended in the horizontal direction. This may result in the creation of two horizontal wells that are vertically spaced from, but otherwise vertically aligned with, one another. Ideally, the production well is located above the base of the reservoir but as close as practical to the bottom of the reservoir, and the injection well is located vertically 10 to 30 feet (3 to 10 meters) above the horizontal well used for production.
The upper horizontal well is utilized as an injection well and is supplied with steam from the surface. The steam rises from the injection well, permeating the reservoir to form a vapor chamber that grows over time towards the top of the reservoir, thereby increasing the temperature within the reservoir. The steam, and its condensate, raise the temperature of the reservoir and consequently reduce the viscosity of the heavy oil in the reservoir. The heavy oil and condensed steam will then drain downward through the reservoir under the action of gravity and may flow into the lower production well, whereby these liquids can be pumped to the surface.
At the surface of the well, the condensed steam and heavy oil are separated, and the heavy oil may be diluted with appropriate light hydrocarbons for transport by pipeline.
A number of variations of the SAGD process have been developed in an attempt to increase the productivity of the process. For example, solvents may be used the process, as discussed for CSS.
The techniques discussed above may leave a substantial remainder of hydrocarbons in the reservoir. For example, the techniques for the recovery of resources discussed above may be limited by the presence of high transmissibility zones, e.g., zones of reduced oil saturation, within the reservoir. Such high transmissibility zones may act as both pressure and temperature sinks to the injected fluid being used in the resource recovery processes.
U.S. Pat. No. 3,872,924 to Clampitt teaches a thermal process that relies on a pattern of vertical wells for the recovery of oil from a subterranean reservoir. Steam is injected into a reservoir with an overlying gas cap, and a portion of the injected heat increases the temperature of the gas cap. Water is injected to create a buffer and to reduce gas fingering between the heated gas cap and the associated oil column. Air is then injected and spontaneously combusted in the gas cap, generating heat by burning the residual oil present in the gas cap. The combustion process conductively heats a portion of the oil column, reducing the viscosity of the oil and increasing the gas zone pressure. Both factors help displace the oil and resulting combustion gases to offset a production well's increasing production. This process can be repeated in a cyclic fashion.
However, according to the teachings of Clampitt, the oil production wells are already in place at the time of the in-situ combustion process. This exposes the oil production wells to damage as a result of high gas velocities or very high temperatures that may result from combustion breakthrough at their location.
U.S. Pat. No. 7,900,701 to Weiers, et al., teaches a thermal process that utilizes air injection combined with in-situ combustion in a natural gas zone that is in pressure communication with an underlying heavy oil zone. The in-situ combustion allows for the recovery of a portion of the remaining natural gas at offset production wells without causing an additional decline in the pressure within the reduced oil saturation zone. The residual oil saturation present in the gas zone is used to fuel the combustion process.
However, according to this process, the gas production is shut-in once the combustion gases reach a specific contamination level at the offset gas production wells. Therefore, since the quantity of air consumed to sustain an in-situ combustion process is quite high, the fraction of the total gas cap volume that can be burnt is small.
An embodiment of the present techniques provides a method for heating a hydrocarbon reservoir, wherein the reservoir includes a reduced oil saturation zone in proximity to a heavy oil zone. The method includes injecting an oxidizing gas into the reduced oil saturation zone and combusting hydrocarbons included within the reduced oil saturation zone. The method also includes determining a level of heating within the heavy oil zone that is conductively heated by combustion of the hydrocarbons within the reduced oil saturation zone, and producing hydrocarbons from the heavy oil zone once a desired level of heating has occurred.
Another embodiment provides a system for heating a reservoir. The system includes a reservoir that includes a reduced oil saturation zone in proximity to a heavy oil zone, wherein the reduced oil saturation zone and the heavy oil zone are in thermal communication with one another. The system also includes an injection well, wherein the injection well is located within the reduced oil saturation zone, and wherein the injection well is configured to inject an oxidizing gas into the reduced oil saturation zone to sustain an in-situ combustion of hydrocarbons contained in the reduced oil saturation zone. The system further includes a hydrocarbon recovery system, wherein the hydrocarbon recovery system is located within the heavy oil zone and is configured to produce mobilized fluids from the heavy oil zone.
Another embodiment provides a method for recovering hydrocarbons from a hydrocarbon reservoir, wherein the hydrocarbon reservoir includes a reduced oil saturation zone in thermal communication with a heavy oil zone. The method includes injecting an oxidizing agent into the reduced oil saturation zone and combusting hydrocarbons contained in the reduced oil saturation zone in an in-situ combustion process, wherein conductive heat transferred from the in-situ combustion process heats the hydrocarbons within the heavy oil zone. The method also includes producing the hydrocarbons from the heavy oil zone once a desired level of heating has occurred within the heavy oil zone.
The advantages of the present techniques are better understood by referring to the following detailed description and the attached drawings, in which:
In the following detailed description section, specific embodiments of the present techniques are described. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the techniques are not limited to the specific embodiments described below, but rather, include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.
At the outset, for ease of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or techniques that serve the same or a similar purpose are considered to be within the scope of the present claims.
As used herein, the term “base” indicates a lower boundary of the resources in a reservoir that are practically recoverable, by a gravity-assisted drainage technique, for example, using an injected mobilizing fluid, such as steam, solvents, hot water, gas, and the like. The base may be considered a lower boundary of the pay interval. The lower boundary may be an impermeable rock layer, including, for example, granite, limestone, sandstone, shale, and the like. The lower boundary may also include layers that, while not impermeable, impede the formation of fluid communication between a well on one side and a well on the other side. Such layers may include broken shale, mud, silt, and the like. The resources within the reservoir may extend below the base, but the resources below the base may not be recoverable with gravity-assisted techniques.
“Bitumen” is a naturally occurring heavy oil material. It is often the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 wt. % aliphatics, which can range from 5 wt. %-30 wt. %, or higher;
19 wt. % asphaltenes, which can range from 5 wt. %-30 wt. %, or higher;
30 wt. % aromatics, which can range from 15 wt. %-50 wt. %, or higher;
32 wt. % resins, which can range from 15 wt. %-50 wt. %, or higher; and
some amount of sulfur, which can range in excess of 7 wt. %.
In addition bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The metals content, while small, can be removed to avoid contamination of the product synthetic crude oil (SCO). Nickel can vary from less than 75 ppm (part per million) to more than 200 ppm. Vanadium can range from less than 200 ppm to more than 500 ppm. The percentage of the hydrocarbon types found in bitumen can vary.
As used herein, a “cyclic recovery process” uses an intermittent injection of a mobilizing fluid selected to lower the viscosity of heavy oil in a hydrocarbon reservoir. The injected mobilizing fluid may include steam, solvents, gas, water, or any combinations thereof. After a soak period, intended to allow the injected material to interact with the heavy oil in the reservoir, the material in the reservoir, including the mobilized heavy oil and some portion of the mobilizing agent may be harvested from the reservoir. Cyclic recovery processes use multiple recovery mechanisms, in addition to gravity drainage, early in the life of the process. The significance of these additional recovery mechanisms, for example dilation and compaction, solution gas drive, water flashing, and the like, declines as the recovery process matures. Practically speaking, gravity drainage is the dominant recovery mechanism in all mature thermal, thermal-solvent and solvent based recovery processes used to develop heavy oil and bitumen deposits. For this reason the approaches disclosed here are equally applicable to all recovery processes in which, at the current stage of depletion, gravity drainage is the dominant recovery mechanism.
As used herein, “condensate” includes liquid water formed by the condensation of steam. Steam may also entrain liquid water, in the form of water droplets. This entrained water may also be termed condensate, as it may arise from condensation of the steam, although the entrained water droplets may also originate from the incomplete conversion of liquid water to steam in a boiler.
A “development” is a project for the recovery of hydrocarbons using integrated surface facilities and long term planning. The development can be directed to a single hydrocarbon reservoir, although multiple proximate reservoirs may be included.
As used herein, “exemplary” means “serving as an example, instance, or illustration.” Any embodiment described herein as “exemplary” is not to be construed as preferred or advantageous over other embodiments.
“Heavy oil” includes oils which are classified by the American Petroleum Institute (API), as heavy oils or extra heavy oils. In general, a heavy oil has an API gravity between 22.3° (density of 920 kg/m3 or 0.920 g/cm3) and 10.0° (density of 1,000 kg/m3 or 1 g/cm3). An extra heavy oil, in general, has an API gravity of less than 10.0° (density greater than 1,000 kg/m3 or greater than 1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water, and bitumen. The thermal recovery of heavy oils is based on the viscosity decrease of fluids with increasing temperature or solvent concentration. Once the viscosity is reduced, the mobilization of fluids by steam, hot water flooding, or gravity is possible. The reduced viscosity makes the drainage quicker and therefore directly contributes to the recovery rate.
A “hydrocarbon” is an organic compound that primarily includes the elements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. As used herein, hydrocarbons are used to refer to components found in bitumen, or other oil sands.
“Pore volume” is defined as the volume of fluid associated with a portion of a reservoir. It is the product of the average porosity of the reservoir and the volume of the portion of the reservoir in question.
As used herein, a “reservoir” is a subsurface rock or sand formation from which a production fluid can be harvested. The rock formation may include sand, granite, silica, carbonates, clays, and organic matter, such as oil, gas, or coal, among others. Reservoirs can vary in thickness from less than one foot (0.3048 m) to hundreds of feet (hundreds of m).
“Shale” is a fine-grained clastic sedimentary rock with a mean grain size of less than 0.0625 mm. Shale typically includes laminated and fissile siltstones and claystones. These materials may be formed from clays, quartz, and other minerals that are found in fine-grained rocks. Shale has low matrix permeability, so gas production in commercial quantities often requires fractures to provide permeability. Shale gas reservoirs may be hydraulically fractured to create extensive artificial fracture networks around wellbores. Horizontal drilling is often used with shale gas wells.
As discussed above, “steam assisted gravity drainage” (SAGD) is a thermal recovery process in which steam is injected into a first well to lower a viscosity of a heavy oil, and fluids are recovered from a second well. Both wells are usually horizontal in the formation and the first well lies above the second well.
Accordingly, the reduced viscosity heavy oil flows down to the second well under the force of gravity, although pressure differential may provide some driving force in various applications.
“Substantial” when used in reference to a quantity or amount of a material, or a specific characteristic thereof, refers to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may in some cases depend on the specific context.
“Transmissibility” refers to the volumetric flow rate between two points at unit viscosity for a given pressure-drop. Transmissibility is a useful measure of connectivity. Transmissibility between any two compartments in a reservoir, or between the well and the reservoir, or between injection wells and production wells, can all be useful for characterizing connectivity in the reservoir.
“Viscosity” is the resistance of a fluid or slurry to flow, defined as the ratio of shear stress to shear rate. The unit of viscosity is Poise, equivalent to dyne-sec/cm2. Because one poise represents a relatively-high viscosity, 1/100 poise, or one centipoise (“cP”), is usually used with regard to well treatment fluids. Viscosity must have a stated or an understood shear rate in order to be meaningful. Measurement temperature also must be stated or understood.
As used herein, “thermal recovery processes” include any type of hydrocarbon recovery process that uses a heat source to enhance the recovery, for example, by lowering the viscosity of a hydrocarbon. These processes may be based on heated water, wet steam, or dry steam, alone, or in any combinations.
Further, any of these components may be combined with solvents to enhance the recovery. Such processes may include subsurface processes, such as cyclic steam stimulation (CSS), steamflooding, and SAGD, among others, and processes that use surface processing for the recovery, such as sub-surface mining and surface mining.
A “wellbore” is a hole in the subsurface made by drilling or inserting a conduit into the subsurface. A wellbore may have a substantially circular cross section or any other cross-sectional shape, such as an oval, a square, a rectangle, a triangle, or other regular or irregular shapes. As used herein, the term “well,” when referring to an opening in the formation, may be used interchangeably with the term “wellbore.” Further, multiple pipes may be inserted into a single wellbore, for example, to limit frictional forces in any one pipe.
As used herein, two locations in a reservoir are in “fluid communication” when a path for fluid flow exists between the locations. For example, the establishment of fluid communication between a lower-lying production well and a higher injection well may allow material mobilized from a steam chamber above the injection well to flow down to the production well from collection and production. As used herein, a fluid includes a gas or a liquid and may include, for example, a produced hydrocarbon, an injected mobilizing fluid, or water, among other materials.
As used herein, two locations in a reservoir are in “thermal communication” when a transfer of heat between the two locations is possible. The heat may be transferred between the two locations via any path that is capable of thermal conduction, i.e., heat conduction. For example, for two zones that are in thermal communication with one another, if the temperature is raised in one zone, some level of temperature response will be observed in the other zone given enough time to offset the separation.
Embodiments described herein provide a system and methods relating to the application of in-situ combustion to a pre-existing high transmissibility zone, or reduced oil saturation zone, to conductively heat, and thereby reduce the viscosity of, the resources within a reservoir. Such a system and methods may be implemented prior to the implementation of a gravity drainage based recovery process. In various embodiments, the resources to be recovered include hydrocarbons.
Because the heating process relies on conductive heating as a result of in-situ combustion, the system and methods disclosed herein may be characterized by a number of conditions. For example, in some cases, the pre-existing high transmissibility zone may not be in pressure communication with or directly adjacent to the reservoir to be heated. The combination of oxidizing agent injection rates and the number and placement of oxidizing agent injection wells may be sufficient to allow the continued propagation of the burn through the pre-existing high transmissibility zone. The volume of combustion gas products that result from the system and methods disclosed herein may also be properly managed. In addition, the wellbores, e.g., a well pair including a production well and an injection well, to be used in the thermal or thermal-solvent based recovery process may not be drilled prior to or during the active in-situ combustion phase, or may be located in such a way that the wellbores do not pass through the expected in-situ combustion interval.
Further, the start of the thermal or thermal-solvent based recovery process may be delayed relative to the passing of the in-situ combustion front at that location in order to capture the benefits of the conductive heating.
High transmissibility zones, such as top gas, top water, or interstitial lean zones that are within or directly adjacent to an oil reservoir are usually viewed as being a negative influence on the performance of a thermal or thermal-solvent based recovery process, as their presence imposes certain constraints on the recovery process operation. One example would be the need to operate at a specific operating pressure to minimize the volume of injectant lost to the high transmissibility zone. If the high transmissibility zone is isolated from the oil reservoir, then these intervals may be viewed as benign.
Typically, high transmissibility zones have an oil content that is reduced relative to other regions within the reservoir. In top gas and top water zones associated with heavy oil reservoirs, the oil content is typically between 0.1 and 0.4 pore volume. In an interstitial lean zone, the water content is typically between 0.1 to 0.3 pore volume higher than in other regions of the oil reservoir, but it can still be less than the oil content of the lean zone.
In embodiments disclosed herein, the hydrocarbons, e.g., oils, present in the high transmissibility zone are used as the fuel source to sustain an in-situ combustion process. Heat losses that are a by-product of the in-situ combustion process, e.g. heat losses in the form of conduction, will gradually warm an adjacent heavy oil zone. This heating will improve the efficiency of the thermal or thermal-solvent based recovery process by both reducing heat losses from the heavy oil zone and reducing the fraction of the injected heat that is consumed heating the heavy oil zone to the desired operating temperature.
Once the combustion front has passed a specific location within the lean zone, the time to heat the heavy oil zone is typically a function of at least three conditions. The first condition is the vertical separation between the high transmissibility zone undergoing in-situ combustion and the heavy oil zone. The second condition is the thickness of the heavy oil zone. The third condition is the desired level of heating within the heavy oil zone. In various embodiments, in locations where there are two vertically stacked heavy oil zones, with the lower heavy oil zone also containing a gas zone, conductive heat losses can heat both heavy oil zones.
In a conventional in-situ combustion process, a portion of the oil or other resources targeted for recovery is consumed in the combustion process. Separations between production wells and injection wells are usually relatively small, e.g., a few hundred meters or less, to allow the quick capture of the mobilized oil. In a 5, 7, or 9 spot pattern combustion project, once the combustion front nears a production well, the air injection is typically transferred to a new pattern. For example, in the case of a line drive, the production wells may be transformed into injection wells, and a new set of production wells may be activated.
In various embodiments, the hydrocarbon being burned within the high transmissibility zone is not equivalent to the hydrocarbon being targeted by the thermal or thermal-solvent based recovery process. The low initial oil saturations cause the risk of plugging within the high transmissibility zone during the in-situ combustion process to be relatively low. Further, because hydrocarbon production as a direct result of the in-situ combustion process is not the intent, much larger separations can be used between the air injection wells and combustion-gas production wells.
In order to ensure that the in-situ combustion process is sustainable, a number of conditions may be met. First, a sufficient volume of air, or other type of oxidizing agent, to support combustion must be present in the pore space within the high transmissibility zone. Second, a sufficient volume of air to maintain the minimum gas flux at the combustion front to sustain combustion must be injected. Third, lateral continuity must exist between the air injection wells and the combustion-gas production wells. Fourth, sufficient in-situ storage capacity or combustion gas clean-up capabilities must be available for the combustion gases.
In various embodiments, a line drive configuration of injection wells and production wells may be used, meaning that the injection wells are arranged in a straight line parallel to the production wells or, in the case of a single injection well, the injection well is arranged perpendicular to the production wells. The current industry norm is to utilize vertical or deviated wells as air injection wells, especially in areas where initial reservoir temperatures are insufficient to enable spontaneous combustion to occur once air injection has begun. When vertical injection wells are used, the separation between the injection wells may be determined based on the separation that causes the combustion front velocity during the initial radial growth phase to remain above the minimum level for sustaining the combustion process. Once the radial combustion fronts associated with adjacent injection wells have merged, the surface area of the combustion front declines, resulting in higher air fluxes for the same air injection rate. The net result is that large areas of the high transmissibility zone can be combusted using significantly fewer wells than would be considered viable in a conventional in-situ combustion project.
Horizontal wells that are used as injection wells may have a liner design that regulates both the location of air injection and the quantity of air being injected per location along the length of the horizontal liner. This level of control can be achieved through the use of a series of restrictive exit points along the liner. Such exit points can be as simple as a limited number of drilled holes along the length of the horizontal liner that impose a restrictive pressure drop at a specified air injection rate and pressure. In addition, the exits points can be a liner design consistent with U.S. Pat. No. 6,158,510 to Bacon, et al., in which a wire-wrap screen is included, external to the drilled holes, to help distribute the injected air within the formation.
In various embodiments, pyrophoric chemicals, such as calcium phosphide, triethylborane (TEB), silane, disilane, and linseed oil containing catalysts such as cobalt naphtheneate and dimethyl aniline can be used as igniters. To enable their safe usage with a horizontal injection well, the holes in the liner may be vertically downward oriented, preferably in the structural lows along the trajectory of the liner. Vertical undulations can be proactively added to the horizontal well profile to create the desired locations for the low points. In this way, the potential for the chemicals accumulating in the liner is minimized.
In some embodiments, a wide separation between the line of air injection wells and combustion-gas production wells may be maintained. In some cases, this may be aided by the level of compartmentalization that exists within the high transmissibility zone. This level of compartmentalization can be caused by lateral and vertical changes in geologic faces, the orientation of the geologic beds, or post depositional structural changes, among others. Additionally, the injection wells and production wells may be located such that the combustion front is able to sweep along the longest axis of the high transmissibility zone. This allows for the maintenance of the highest frontal velocity for a given air injection rate.
Embodiments disclosed herein provide for the management of the combustion gases produced from the in-situ combustion process. For example, sufficient accommodation space in front of the combustion front may be created to allow the resulting volume of combustion gases to be removed. For example, 10 to 15 standard cubic meters of air may be used to combust 1 kg of heavy oil.
In some embodiments, a portion of the produced gas can be sold, used on site for fuel, or incinerated, depending on the BTU (British thermal unit) content of the produced gas. Additionally, a portion of the produced gas can be reinjected into a different reservoir and stored in-situ. Examples of in-situ storage include partially or fully pressure depleted gas pools and mature parts of the oil development where adequate voidage is present. In addition, compression of the produced gas may or may not be performed to allow one or more of these options to be implemented.
In various embodiments, as the combustion front progresses through the lean zone, i.e., the high transmissibility zone, the volume of air inventoried behind the combustion front in the already burnt portion of the reservoir grows. Once the entire high transmissibility zone has been combusted, mostly air will be present. In order to minimize the volume of air that is injected but not consumed in the combustion process, the in-situ combustion process may be operated at a low pressure over the majority of the process life. This may also help to reduce air compression costs. In addition, when the volume of air inventoried behind the combustion front is estimated to be equivalent to that required to complete the combustion of the remaining portions of the high transmissibility zone, air injection may be stopped, and some or all of the produced gases, after recompression, can be reinjected via the air injection wells. These gases may displace the inventoried air to the combustion front.
In some embodiments, the high transmissibility zone may be in direct contact with the heavy oil zone. In such cases, during the later stages of the combustion process, the production of the combustion gases can be restricted to a level less than the gas injection rate. This may allow the pressure in the high transmissibility zone to increase to that desired for the planned implementation of the thermal or thermal-solvent based recovery process.
Further, in some embodiments, the temperatures at the combustion front can exceed 600° C. during combustion. Due to the low heat capacity of gases, only a small fraction of this heat will be consumed heating the injected air as it travels toward the combustion front. The remaining portions of the heat will gradually conduct into the strata surrounding the high transmissibility zone, increasing the temperature of the rock and fluids present in these strata. The distance away from the physical combustion zone that the heat can be conducted is dependent on the time that the conduction is allowed to occur. The longer the time, the deeper the heat will penetrate. Even after the thermal or thermal-solvent based recovery process has started operation, the conductive heat from the combustion process will continue to diffuse into the heavy oil zone. This heating will improve the efficiency of the thermal or thermal-solvent based recovery process by reducing heat losses from the heavy oil zone, as well as reducing the heat consumed heating the heavy oil zone.
According to embodiments disclosed herein, SAGD is used as the representative thermal or thermal-solvent based recovery process. In addition, a top gas interval that is hydraulically isolated from an associated oil column is used as the representative high transmissibility zone, or reduced oil saturation zone. However, those of ordinary skill in the art will recognize that embodiments disclosed herein are equally applicable to all thermal and thermal-solvent based recovery processes and to all high transmissibility zones that are in reasonable proximity to an associated heavy oil zone.
System for Heating a Reservoir and Producing Resources from the Reservoir According to a SAGD Process
A shale layer 108 may be located between the reduced oil saturation zone 104 and the heavy oil zone 106. In various embodiments, the shale layer 108 may partially or completely isolate the reduced oil saturation zone 104 from the heavy oil zone 106. However, the reduced oil saturation zone 104 and the heavy oil zone 106 may still be in thermal communication, via conductive heat transfer, with one another. The reduced oil saturation zone 104 may be located above or below the heavy oil zone 106, or may be located between multiple heavy oil zones. Further, in various embodiments, the separation between the reduced oil saturation zone 104 and the heavy oil zone 106 is less than 15 meters.
The system 100 may also include an injection well 110 and a production well 112 extending into the reduced oil saturation zone 104. In some embodiments, the injection well 110 and the production well 112 may be drilled from the same pad 114 at the surface 116, as shown in
The injection well 110 may inject an oxidizing gas 118, or oxidizing agent, such as air, enriched air, or oxygen, among others, into the reduced oil saturation zone 104. The oxidizing gas 118 may react with oil present within the reduced oil saturation zone 104 according to the in-situ combustion process, producing a considerable amount of heat.
The production well 112 may be used to send gas 120 produced from the in-situ combustion process within the reduced oil saturation zone 104 to a processing facility 122. The gas 120 may include natural gas present within the reduced oil saturation zone 104 (such as methane or carbon dioxide, among others), combustion by-products (such as carbon dioxide, carbon monoxide, or nitrogen, among others), or products formed from the heating of the reduced oil saturation zone 104 (such as hydrogen, among others). The gas 120 may then be offloaded from the processing facility 122, used for fuel, used for an enhanced oil recovery process, or stored in another reduced oil saturation zone.
Some amount of the heat produced from the in-situ combustion process within the reduced oil saturation zone 104 can diffuse from the reduced oil saturation zone 104 to the heavy oil zone 106. Such heat will raise the temperature and, thus, lower the viscosity of the hydrocarbons or other resources within the heavy oil zone 106. This can prepare the hydrocarbons or other resources to be produced from the heavy oil zone 106 via the SAGD process.
In the SAGD process, steam 124 can be injected through an injection well 126 to the heavy oil zone 106. The injection well 126 may be horizontally drilled through the heavy oil zone 106 within the reservoir 102. A production well 128 may also be horizontally drilled through the heavy oil zone 106, and may be located underneath the injection well 126. In some embodiments, the injection well 126 and the production well 128 may be drilled from the same pad 130 at the surface 116. This may make it easier for the production well 128 to track the injection well 126. However, in some embodiments the injection well 126 and the production well 128 may be drilled from different pads.
The injection of the steam 124 into the injection well 126 may result in the mobilization of hydrocarbons 132, which may drain to the production well 128 and be removed to the surface 116 in a mixed stream 134 that can contain hydrocarbons, condensate and other materials, such as water, gases, and the like. As described herein, a screen assembly (not shown) may be used on the injection well 126, for example, to throttle the inflow of injectant vapor to the heavy oil zone 106. Similarly, a screen assembly (not shown) may be used on the production well 128, for example, to decrease sand entrainment.
The hydrocarbons 132 may form a triangular shaped drainage chamber 136 that has the production well 128 located at a lower apex. The mixed stream 134 from the production well 128 may be sent to the processing facility 122. At the processing facility 122, the water and hydrocarbons 138 can be separated, and the hydrocarbons 138 can sent on for further refining. Water from the separation may be recycled to a steam generation unit within the processing facility 122, with or without further treatment, and used to generate the steam 120 used for the SAGD process.
In various embodiments, the production well 128 and the injection well 126 form a well pair 140 that may be used for a gravity drainage based process, including thermal or thermal-solvent based recovery processes. The production well 128 and the injection well 126 may have a segment that is relatively flat and, in some circumstances, has a slight upward slope from the heel 142, at which the pipe branches to the surface 116, to the toe 144, at which the pipe ends. The production well 128 may be designed such that it follows the trajectory of the injection well 126 along a base 146 of the heavy oil zone 106, or of the reservoir 102.
It is to be understood that
Exemplary Reservoirs with Reduced Oil Saturation Zones
Some of the factors that influence the effectiveness of the pre-heating process are: (1) the physical distance between the reduced oil saturation zone 304 and the heavy oil zone; (2) the thickness of the heavy oil zone to be conductively heated; and (3) the total time available for the conductive heating process to occur. These three factors will influence the orientation, or direction of lateral sweep, of the in-situ combustion process.
Depending on the circumstances, it might be advantageous to initiate the in-situ combustion where the shale layer 422 is thinnest, even though the heavy oil zone 420 is also thinner in this area, or it might be advantageous to initiate the in-situ combustion where the shale layer 422 is thickest, even though the level of heating that will occur in the heavy oil zone 420 may be less.
The in-situ combustion system 500 may include an injection well 504 and two production wells 506, as shown in
The specific area that may be covered by the combustion front 508 may be predicted if a number of assumptions are made. For example, it may be assumed that the injection well 504 is capable of injecting 70,000 standard cubic meters per day (sm3/d) of air, the reduced oil saturation zone is 5 m thick, and the pressure within the reduced oil saturation zone is maintained at a constant 1 MPa. It may also be assumed that the porosity within the reduced oil saturation zone is 0.33, the oil burnt in the combustion reaction is 0.1 pore volume, 13,000 sm3 of air is used for the combustion of 1 m3 of oil, and the critical combustion front velocity is 0.038 m/d. If all of these assumptions are made, the combustion front 508 would be expected to stall 140 to 150 meters away from the injection well 504 after 5 to 6 years of operation. Over this period of time, more than 130 million sm3 of air will have been injected, with the oxygen having been converted to a mixture of carbon dioxide and carbon monoxide. At reservoir conditions, this air volume represents more than 500 times the combusted region pore volume within the reservoir.
In various embodiments, the production wells 506 may be used to produce gases from the reduced oil saturation zone 502. Such gases may include natural gas present within the reduced oil saturation zone 502 (such as methane or carbon dioxide, among others), combustion by-products (such as carbon dioxide, carbon monoxide, or nitrogen, among others), or products formed from the heating of the reduced oil saturation zone 502 (such as hydrogen, among others). The produced gas may then be used as on-site fuel, sold, incinerated, stored in depleted oil or gas reservoirs, or stored in reservoirs that have not been developed.
The reduced oil saturation zone may include an in-situ combustion system configured to allow for the implementation of the in-situ combustion process. The in-situ combustion system may include an injection well and one or more production wells arranged in an appropriate configuration, which may be determined according to the specific application and location. The injection well may be a vertical injection well, a deviated injection well, a slanted injection well, or a horizontal injection well, or any combinations thereof.
The heavy oil zone may include a hydrocarbon recovery system that is configured to produce mobilized fluids, e.g., hydrocarbon resources or other resources, from the heavy oil zone. The hydrocarbon recovery system may include one or more injection wells and one or more production wells. For example, in some embodiments, the hydrocarbon recovery system may include a SAGD well pair. Further, the one or more injection wells and one or more production wells of the hydrocarbon recovery system may be drilled in an offset location such that the trajectories of the wells do not pass through the reduced oil saturation zone.
The method begins at block 702 with the injection of an oxidizing gas into the reduced oil saturation zone. At block 704, a combustion of hydrocarbons in the reduced oil saturation zone is performed. This may be a continuing combustion, or may be ignited by the injection of a pyrophoric compound before or after the oxidizing gas. The oxidizing gas may react with hydrocarbons present in the reduced oil saturation zone to sustain an in-situ combustion in the reduced oil saturation zone.
Heat released from the in-situ combustion may dissipate from the reduced oil saturation zone to the heavy oil zone, resulting in an increase in the temperature of the hydrocarbons within the heavy oil zone. Such an increase in temperature may result in the lowering of the viscosity of the hydrocarbons. In other words, the higher the temperature of the hydrocarbons, the less viscous they will become. A lower viscosity is preferable, since it allows for the easier production of the hydrocarbons from the reservoir using the hydrocarbon recovery system.
The amount of time it takes to heat the heavy oil zone as a result of the in-situ combustion may vary depending on the specific characteristics of the corresponding reservoir. In some embodiments, the reduced oil saturation zone may be partially or fully isolated from the heavy oil zone by a shale layer or any other type of low permeability barrier to flow. Thus, the heating of the heavy oil zone may take a long amount of time. In other embodiments, the reduced oil saturation zone may be directly adjacent to, or perhaps even located within, the heavy oil zone. Thus, the heating of the heavy oil zone may take a relatively short amount of time.
At block 706, a determination is made as to whether the heavy oil zone has increased in temperature by a sufficient amount. The determination of when to begin the hydrocarbon production process may be based on the level of heating of the hydrocarbons within the heavy oil zone. Such a level of heating may be measured based on the average temperature of the hydrocarbons, or based on the viscosity of the hydrocarbons. If the temperature increase is determined to not be sufficient at block 706, process flow returns to block 702 to continue the in-situ combustion.
If, at block 706, the temperature increase is determined to be sufficient, at block 708, hydrocarbon production may be started. In various embodiments, hydrocarbon production may be delayed for a certain period of time, such as, for example, 1 day, 1 year, or until the in-situ combustion has been entirely completed.
It is to be understood that
In some embodiments, the reduced oil saturation zone may be in proximity to multiple heavy oil zones. In such cases, the in-situ combustion within the reduced oil saturation zone may be used to heat all of heavy oil zones simultaneously. The amount of time it takes to conductively heat the hydrocarbons within each heavy oil zone may vary according to the respective composition of each heavy oil zone, and the location of each heavy oil zone with respect to the reduced oil saturation zone. In addition, each heavy oil zone may include a hydrocarbon recovery system for producing hydrocarbons. Any number of different types of hydrocarbon recovery systems may be used in each heavy oil zone, including primary, thermal, miscible displacement, or immiscible displacement recovery processes.
The method 700 may also provide for the monitoring of the temperatures and pressures within the reduced oil saturation zone. Such monitoring may be performed to ensure that the integrity of the injection wells and production wells for the in-situ combustion system is not compromised by the harsh conditions. This may be accomplished by drilling the injection well for the in-situ combustion system in a location that is sufficiently far away from the production wells for the in-situ combustion system. Then, the temperatures near the production wells may be monitored, and the in-situ combustion may be terminated once the temperatures are elevated past a certain point. In some embodiments, the gas production wells can be shut-in, with the combustion gases that accumulate around the production wells effectively isolating the production wells from the in-situ combustion. In some cases, previously produced combustion gases or water can be reinjected into the production wells.
Furthermore, in some embodiments, the drilling of the production wells for the hydrocarbon recovery system may be delayed until the in-situ combustion is complete. This may effectively prevent the production wells from being damaged due to harsh conditions within the heavy oil zone from the transfer of conductive heat from the in-situ combustion.
Table 1 is representative of a region in the reduced oil saturation zone where high temperature oxidation combustion reactions dominate, while Table 2 is representative of a region in the reduce oil saturation zone where low temperature oxidation reactions dominate. After around 3 years, significant heating is observed 10 to 15 meters away from the combustion interval. Thus, even if a portion of the reduced oil saturation zone and the heavy oil zone is separated by a 5 meter thick shale layer, significant heating of the hydrocarbons within the heavy oil zone is still observed.
Embodiments of the invention may include any combinations of the methods and systems shown in the following numbered paragraphs. This is not to be considered a complete listing of all possible embodiments, as any number of variations can be envisioned from the description above.
1. A method for heating a hydrocarbon reservoir, wherein the reservoir includes a reduced oil saturation zone in proximity to a heavy oil zone, the method including:
2. The method of paragraph 1, including allowing gases to accumulate within the reduced oil saturation zone.
3. The method of paragraph 1 or 2, including producing gases from the reduced oil saturation zone.
4. The method of paragraph 3, including using at least a portion of the gases produced for fuel.
5. The method of paragraph 3, including using at least a portion of the gases in an enhanced oil recovery process.
6. The method of paragraph 3, including storing at least a portion of the gases in another reservoir.
7. The method of any of paragraphs 1-3, wherein the reduced oil saturation zone includes an oil reservoir that is at least partially depleted.
8. The method of any of paragraphs 1-3 or 7, wherein the reduced oil saturation zone is isolated from the heavy oil zone by at least one low permeability barrier to flow.
9. The method of any of paragraphs 1-3, 7, or 8, wherein the oxidizing gas includes air, enriched air, or oxygen, or any combinations thereof.
10. The method of any of paragraphs 1-3 or 7-9, including removing at least a portion of mobile water present in the reduced oil saturation zone.
11. A system for heating a reservoir, including:
12. The system of paragraph 11, including a production well, wherein the production well is located within the reduced oil saturation zone and is configured to produce gas produced from the reduced oil saturation zone.
13. The system of paragraph 11 or 12, wherein the reduced oil saturation zone is located above the heavy oil zone.
14. The system of any of paragraphs 11-13, wherein the reduced oil saturation zone is located within the heavy oil zone.
15. The system of any of paragraphs 11-14, wherein the reduced oil saturation zone is located below the heavy oil zone.
16. The system of any of paragraphs 11-15, wherein the reduced oil saturation zone is located between two vertically separated heavy oil zones.
17. The system of any of paragraphs 11-16, wherein the hydrocarbon recovery system includes a production well at a first elevation and an injection well at a higher elevation.
18. The system of paragraph 17, wherein the production well and the injection well are drilled either during the in-situ combustion, or after the in-situ combustion is complete.
19. The system of paragraph 17, wherein the production well and the injection well are drilled before a combustion front from the in-situ combustion passes above a location of the production well and the injection well.
20. The system of paragraph 17, wherein the production well and the injection well are drilled from offset locations such that a trajectory of the production well and a trajectory of the injection well do not pass through the reduced oil saturation zone.
21. The system of any of paragraphs 11-17, where the injection well includes a vertical injection well, a deviated injection well, a slanted injection well, or a horizontal injection well, or any combinations thereof.
22. The system of any of paragraphs 11-17 or 21, wherein the reservoir includes a reduced oil saturation zone in proximity to a number of heavy oil zones.
23. The system of paragraph 22, including a hydrocarbon recovery system located within each of the number of heavy oil zones.
24. The system of any of paragraphs 11-17, 21, or 22, including a layer of shale located between the reduced oil saturation zone and the heavy oil zone.
25. The system of any of paragraphs 11-17 or 21, 22, or 24, wherein the reduced oil saturation zone includes a high transmissibility zone.
26. A method for recovering hydrocarbons from a hydrocarbon reservoir, wherein the hydrocarbon reservoir includes a reduced oil saturation zone in thermal communication with a heavy oil zone, and wherein the method includes:
27. The method of paragraph 26, including producing gas from the in-situ combustion process within the reduced oil saturation zone.
28. The method of paragraph 26, wherein the oxidizing agent includes air, enriched air, or oxygen, or any combinations thereof.
While the present techniques may be susceptible to various modifications and alternative forms, the embodiments discussed above have been shown only by way of example. However, it should again be understood that the techniques is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present techniques include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.
| Number | Date | Country | Kind |
|---|---|---|---|
| 2,766,844 | Feb 2012 | CA | national |
