CORE SAMPLE TESTING
One embodiment of a method of performing a test on a core sample comprises transferring at least a portion of a core sample from a first core containment vessel to a second core containment vessel. The core sample is maintained at a substantially equivalent pressure or placed under a higher pressure during the transfer of the core sample from the first vessel to the second vessel. The method further comprises performing a test on the core sample in a measurement region of the second vessel.
The present application claims priority under 35 U.S.C. Section 119(e) to U.S. Provisional Patent Application No. 62/881,797, filed Aug. 1, 2019, and titled “Core Sample Testing,” U.S. Provisional Patent Application No. 62/881,787, filed Aug. 1, 2019, and titled “Pressurized Reservoir Core Sample Transfer Tool System,” and U.S. Provisional Patent Application No. 63/050,662, filed Jul. 10, 2020, and titled “Pressurized Reservoir Core Sample Transfer Tool System,” the entire contents of which is incorporated herein by reference. The present application is also related to U.S. patent application Ser. No. 16/944,542, filed Jul. 31, 2020, and titled “Pressurized Reservoir Core Sample Transfer Tool System,” the entire content of which is incorporated herein by reference.
TECHNICAL FIELDThe present application relates generally to methods of testing core samples in the hydrocarbon industry.
BACKGROUNDEvaluation of potential oil and gas reservoirs is highly dependent on the collection and analysis of subsurface core samples removed from wells. These cores are conventionally extracted in lengths of 30 feet or longer, each representing a continuous range of drilled depth into the formation. Smaller core plugs are later cut from the core to sample at particular depths of interest. Sidewall core samples with size on the order of several inches can also be individually extracted from near the wall of the well. In either case, as the samples are returned from the well to the surface, they typically experience a change in pressure on the order of thousands to tens of thousands of pounds per square inch (psi), depending on the total vertical depth traveled. This pressure change typically affects the phase and composition of the fluids contained in the rock sample, for example, causing lighter hydrocarbon molecules to volatilize and leave the sample. It may also result in structural alterations to the rock, such as the formation of fractures, changes in rock fabric, or changes in pore geometry. Laboratory core measurements are performed after these composition and structural changes have occurred, so the lab data may not necessarily represent the native state of the samples in their original downhole environment.
Improvements in the testing of core samples is therefore needed.
SUMMARYIn one aspect, a method of performing a test on a core sample retrieved from a wellbore of a subterranean reservoir includes transferring at least a portion of a core sample from a first core containment vessel, or first vessel, to a second core containment vessel, or second vessel. The core sample is maintained at a substantially equivalent pressure or placed under a higher pressure during the transfer of the core sample from the first vessel to the second vessel. The method further includes performing a test on the core sample in a measurement zone of the second vessel. In some instances, the first vessel encloses the core sample in a sealed chamber at a pressure above ambient pressure, where the pressure is representative of a pressure from which the core sample was retrieved. In some instances, the test may be a magnetic resonance test, a computed tomography test, a neutron test, an acoustic test, a dielectric test, or any combination thereof.
For a more complete understanding of the exemplary embodiments of the present invention and the advantages thereof, reference is now made to the following description in conjunction with the accompanying drawings, which are briefly described as follows.
TERMINOLOGY: The following terms will be used throughout the specification and will have the following meanings unless otherwise indicated.
Formation: Hydrocarbon exploration processes, hydrocarbon recovery (also referred to as hydrocarbon production) processes, or any combination thereof may be performed on a formation. The formation refers to practically any volume under a surface. For example, the formation may be practically any volume under a terrestrial surface (e.g., a land surface), practically any volume under a seafloor, etc. A water column may be above the formation, such as in marine hydrocarbon exploration, in marine hydrocarbon recovery, etc. The formation may be onshore. The formation may be offshore (e.g., with shallow water or deep water above the formation). The formation may include faults, fractures, overburdens, underburdens, salts, salt welds, rocks, sands, sediments, pore space, etc. Indeed, the formation may include practically any geologic point(s) or volume(s) of interest (such as a survey area) in some embodiments.
The formation may include hydrocarbons, such as liquid hydrocarbons (also known as oil or petroleum), gas hydrocarbons (e.g., natural gas), solid hydrocarbons (e.g., asphaltenes or waxes), a combination of hydrocarbons (e.g., a combination of liquid hydrocarbons, gas hydrocarbons, and solid hydrocarbons), etc. Light crude oil, medium oil, heavy crude oil, and extra heavy oil, as defined by the American Petroleum Institute (API) gravity, are examples of hydrocarbons. Examples of hydrocarbons are many, and hydrocarbons may include oil, natural gas, kerogen, bitumen, clathrates (also referred to as hydrates), etc. The hydrocarbons may be discovered by hydrocarbon exploration processes.
The formation may also include at least one wellbore. For example, at least one wellbore may be drilled into the formation in order to confirm the presence of the hydrocarbons. As another example, at least one wellbore may be drilled into the formation in order to recover (also referred to as produce) the hydrocarbons. The hydrocarbons may be recovered from the entire formation or from a portion of the formation. For example, the formation may be divided into one or more hydrocarbon zones, and hydrocarbons may be recovered from each desired hydrocarbon zone. One or more of the hydrocarbon zones may even be shut-in to increase hydrocarbon recovery from a hydrocarbon zone that is not shut-in.
The formation, the hydrocarbons, or any combination thereof may also include non-hydrocarbon items. For example, the non-hydrocarbon items may include connate water, brine, tracers, items used in enhanced oil recovery or other hydrocarbon recovery processes, items from other treatments (e.g., items used in conformance control), etc.
In short, each formation may have a variety of characteristics, such as petrophysical rock properties, reservoir fluid properties, reservoir conditions, hydrocarbon properties, or any combination thereof. For example, each formation (or even zone or portion of the formation) may be associated with one or more of: temperature, porosity, salinity, permeability, water composition, mineralogy, hydrocarbon type, hydrocarbon quantity, reservoir location, pressure, etc. Indeed, those of ordinary skill in the art will appreciate that the characteristics are many, including, but not limited to: shale gas, shale oil, tight gas, tight oil, tight carbonate, carbonate, vuggy carbonate, unconventional (e.g., a rock matrix with an average pore size less than 1 micrometer), diatomite, geothermal, mineral, metal, a formation having a permeability in the range of 0.01 microdarcy to 10 millidarcy, a formation having a permeability in the range of 10 millidarcy to 40,000 millidarcy, etc.
The terms “formation”, “subsurface formation”, “hydrocarbon-bearing formation”, “reservoir”, “subsurface reservoir”, “subsurface region of interest”, “subterranean reservoir”, “subsurface volume of interest”, and the like may be used synonymously. The terms “formation”, “hydrocarbons”, and the like are not limited to any description or configuration described herein.
Wellbore: A wellbore refers to a single hole, usually cylindrical, that is drilled into the formation for hydrocarbon exploration, hydrocarbon recovery, surveillance, or any combination thereof. The wellbore is usually surrounded by the formation and the wellbore may be configured to be in fluidic communication with the formation (e.g., via perforations). The wellbore may also be configured to be in fluidic communication with the surface, such as in fluidic communication with a surface facility that may include oil/gas/water separators, gas compressors, storage tanks, pumps, gauges, sensors, meters, pipelines, etc.
The wellbore may be used for injection (sometimes referred to as an injection wellbore) in some embodiments. The wellbore may be used for production (sometimes referred to as a production wellbore) in some embodiments. The wellbore may be used for a single function, such as only injection, in some embodiments. The wellbore may be used for a plurality of functions, such as production then injection, in some embodiments. The use of the wellbore may also be changed, for example, a particular wellbore may be turned into an injection wellbore after a different previous use as a production wellbore. The wellbore may be drilled amongst existing wellbores, for example, as an infill wellbore. A wellbore may be utilized for injection and a different wellbore may be used for hydrocarbon production, such as in the scenario that hydrocarbons are swept from at least one injection wellbore towards at least one production wellbore and up the at least one production wellbore towards the surface for processing. On the other hand, a single wellbore may be utilized for injection and hydrocarbon production, such as a single wellbore used for hydraulic fracturing and hydrocarbon production. A plurality of wellbores (e.g., tens to hundreds of wellbores) are often used in a field to recover hydrocarbons.
The wellbore may have straight, directional, or a combination of trajectories. For example, the wellbore may be a vertical wellbore, a horizontal wellbore, a multilateral wellbore, an inclined wellbore, a slanted wellbore, etc. The wellbore may include a change in deviation. As an example, the deviation is changing when the wellbore is curving. In a horizontal wellbore, the deviation is changing at the curved section (sometimes referred to as the heel). As used herein, a horizontal section of a wellbore is drilled in a horizontal direction (or substantially horizontal direction). For example, a horizontal section of a wellbore is drilled towards the bedding plane direction. A horizontal section of a wellbore may be, but is not limited to, a horizontal section of a horizontal wellbore. On the other hand, a vertical wellbore is drilled in a vertical direction (or substantially vertical direction). For example, a vertical wellbore is drilled perpendicular (or substantially perpendicular) to the bedding plane direction.
The wellbore may include a plurality of components, such as, but not limited to, a casing, a liner, a tubing string, a heating element, a sensor, a packer, a screen, a gravel pack, artificial lift equipment (e.g., an electric submersible pump (ESP)), etc. The “casing” refers to a steel pipe cemented in place during the wellbore construction process to stabilize the wellbore. The “liner” refers to any string of casing in which the top does not extend to the surface but instead is suspended from inside the previous casing. The “tubing string” or simply “tubing” is made up of a plurality of tubulars (e.g., tubing, tubing joints, pup joints, etc.) connected together. The tubing string is lowered into the casing or the liner for injecting a fluid into the formation, producing a fluid from the formation, or any combination thereof. The casing may be cemented in place, with the cement positioned in the annulus between the formation and the outside of the casing. The wellbore may also include any completion hardware that is not discussed separately. If the wellbore is drilled offshore, the wellbore may include some of the previous components plus other offshore components, such as a riser.
The wellbore may also include equipment to control fluid flow into the wellbore, control fluid flow out of the wellbore, or any combination thereof. For example, each wellbore may include a wellhead, a BOP, chokes, valves, or other control devices. These control devices may be located on the surface, under the surface (e.g., downhole in the wellbore), or any combination thereof. In some embodiments, the same control devices may be used to control fluid flow into and out of the wellbore. In some embodiments, different control devices may be used to control fluid flow into and out of the wellbore. In some embodiments, the rate of flow of fluids through the wellbore may depend on the fluid handling capacities of the surface facility that is in fluidic communication with the wellbore. The control devices may also be utilized to control the pressure profile of the wellbore.
The equipment to be used in controlling fluid flow into and out of the wellbore may be dependent on the wellbore, the formation, the surface facility, etc. However, for simplicity, the term “control apparatus” is meant to represent any wellhead(s), BOP(s), choke(s), valve(s), fluid(s), and other equipment and techniques related to controlling fluid flow into and out of the wellbore.
The wellbore may be drilled into the formation using practically any drilling technique and equipment known in the art, such as geosteering, directional drilling, etc. Drilling the wellbore may include using a tool, such as a drilling tool that includes a drill bit and a drill string. Drilling fluid, such as drilling mud, may be used while drilling in order to cool the drill tool and remove cuttings. Other tools may also be used while drilling or after drilling, such as measurement-while-drilling (MWD) tools, seismic-while-drilling (SWD) tools, wireline tools, logging-while-drilling (LWD) tools, or other downhole tools. After drilling to a predetermined depth, the drill string and the drill bit are removed, and then the casing, the tubing, etc. may be installed according to the design of the wellbore.
The equipment to be used in drilling the wellbore may be dependent on the design of the wellbore, the formation, the hydrocarbons, etc. However, for simplicity, the term “drilling apparatus” is meant to represent any drill bit(s), drill string(s), drilling fluid(s), and other equipment and techniques related to drilling the wellbore.
The term “wellbore” may be used synonymously with the terms “borehole,” “well,” or “well bore.” The term “wellbore” is not limited to any description or configuration described herein.
Hydrocarbon recovery: The hydrocarbons may be recovered (sometimes referred to as produced) from the formation using primary recovery (e.g., by relying on pressure to recover the hydrocarbons), secondary recovery (e.g., by using water injection (also referred to as waterflooding) or natural gas injection to recover hydrocarbons), enhanced oil recovery (EOR), or any combination thereof. Enhanced oil recovery or simply EOR refers to techniques for increasing the amount of hydrocarbons that may be extracted from the formation. Enhanced oil recovery may also be referred to as tertiary oil recovery. Secondary recovery is sometimes just referred to as improved oil recovery or enhanced oil recovery. EOR processes include, but are not limited to, for example: (a) miscible gas injection (which includes, for example, carbon dioxide flooding), (b) chemical injection (sometimes referred to as chemical enhanced oil recovery (CEOR) that includes, for example, polymer flooding, alkaline flooding, surfactant flooding, conformance control, as well as combinations thereof such as alkaline-polymer (AP) flooding, surfactant-polymer (SP) flooding, or alkaline-surfactant-polymer (ASP) flooding), (c) microbial injection, (d) thermal recovery (which includes, for example, cyclic steam and steam flooding), or any combination thereof. The hydrocarbons may be recovered from the formation using a fracturing process. For example, a fracturing process may include fracturing using electrodes, fracturing using fluid (oftentimes referred to as hydraulic fracturing), etc. The hydrocarbons may be recovered from the formation using radio frequency (RF) heating. Other hydrocarbon recovery processes may also be utilized to recover the hydrocarbons. Furthermore, those of ordinary skill in the art will appreciate that one hydrocarbon recovery process may also be used in combination with at least one other recovery process or subsequent to at least one other recovery process. Moreover, hydrocarbon recovery processes may also include stimulation or other treatments.
Other definitions: The term “proximate” is defined as “near”. If item A is proximate to item B, then item A is near item B. For example, in some embodiments, item A may be in contact with item B. For example, in some embodiments, there may be at least one barrier between item A and item B such that item A and item B are near each other, but not in contact with each other. The barrier may be a fluid barrier, a non-fluid barrier (e.g., a structural barrier), or any combination thereof. Both scenarios are contemplated within the meaning of the term “proximate.”
The terms “comprise” (as well as forms, derivatives, or variations thereof, such as “comprising” and “comprises”) and “include” (as well as forms, derivatives, or variations thereof, such as “including” and “includes”) are inclusive (i.e., open-ended) and do not exclude additional elements or steps. For example, the terms “comprises” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof. Accordingly, these terms are intended to not only cover the recited element(s) or step(s), but may also include other elements or steps not expressly recited. Furthermore, as used herein, the use of the terms “a” or “an” when used in conjunction with an element may mean “one,” but it is also consistent with the meaning of “one or more,” “at least one,” and “one or more than one.” Therefore, an element preceded by “a” or “an” does not, without more constraints, preclude the existence of additional identical elements.
The use of the term “about” applies to all numeric values, whether or not explicitly indicated. This term generally refers to a range of numbers that one of ordinary skill in the art would consider as a reasonable amount of deviation to the recited numeric values (i.e., having the equivalent function or result). For example, this term can be construed as including a deviation of ±10 percent of the given numeric value provided such a deviation does not alter the end function or result of the value. Therefore, a value of about 1% can be construed to be a range from 0.9% to 1.1%. Furthermore, a range may be construed to include the start and the end of the range. For example, a range of 10% to 20% (i.e., range of 10%-20%) includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein. Similarly, a range of between 10% and 20% (i.e., range between 10%-20%) includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein.
The term “if” may be construed to mean “when” or “upon” or “in response to determining” or “in accordance with a determination” or “in response to detecting,” that a stated condition precedent is true, depending on the context. Similarly, the phrase “if it is determined [that a stated condition precedent is true]” or “if [a stated condition precedent is true]” or “when [a stated condition precedent is true]” may be construed to mean “upon determining” or “in response to determining” or “in accordance with a determination” or “upon detecting” or “in response to detecting” that the stated condition precedent is true, depending on the context.
It is understood that when combinations, subsets, groups, etc. of elements are disclosed (e.g., combinations of components in a composition, or combinations of steps in a method), that while specific reference of each of the various individual and collective combinations and permutations of these elements may not be explicitly disclosed, each is specifically contemplated and described herein. By way of example, if an item is described herein as including a component of type A, a component of type B, a component of type C, or any combination thereof, it is understood that this phrase describes all of the various individual and collective combinations and permutations of these components. For example, in some embodiments, the item described by this phrase could include only a component of type A. In some embodiments, the item described by this phrase could include only a component of type B. In some embodiments, the item described by this phrase could include only a component of type C. In some embodiments, the item described by this phrase could include a component of type A and a component of type B. In some embodiments, the item described by this phrase could include a component of type A and a component of type C. In some embodiments, the item described by this phrase could include a component of type B and a component of type C. In some embodiments, the item described by this phrase could include a component of type A, a component of type B, and a component of type C. In some embodiments, the item described by this phrase could include two or more components of type A (e.g., A1 and A2). In some embodiments, the item described by this phrase could include two or more components of type B (e.g., B1 and B2). In some embodiments, the item described by this phrase could include two or more components of type C (e.g., C1 and C2). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type A (A1 and A2)), optionally one or more of a second component (e.g., optionally one or more components of type B), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type B (B1 and B2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type C (C1 and C2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type B).
This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to make and use the invention. The patentable scope is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have elements that do not differ from the literal language of the claims, or if they include equivalent elements with insubstantial differences from the literal language of the claims.
Unless defined otherwise, all technical and scientific terms used herein have the same meanings as commonly understood by one of skill in the art to which the disclosed invention belongs. All citations referred herein are expressly incorporated by reference.
OVERVIEW: One embodiment of a method of performing a test on a core sample comprises transferring at least a portion of a core sample from a first core containment vessel, or first vessel, or retrieval vessel, to a second core containment vessel, or second vessel, or testing vessel, and performing a test on the core sample in the second vessel. The core sample is maintained at a substantially equivalent pressure or placed under a higher pressure during the transfer of the core sample from the first vessel to the second vessel. By doing so, the test and the test results may be more accurate (e.g., more representative of reservoir conditions). For example, embodiments consistent with the present disclosure may be utilized for characterizing the core samples and their fluid contents, both while at the initial received pressure and during the depressurization process. Furthermore, embodiments consistent with the present disclosure may be utilized for characterizing core samples that have been recovered and maintained at elevated pressure and/or temperature. In certain embodiments, the core samples have been maintained at the original reservoir pressure and/or temperature, so that there are minimal or no structural changes to the samples, and/or minimal or no changes to the composition and phase of the fluids contained in the samples. In certain embodiments, the core samples have been maintained at representative conditions. In certain exemplary embodiments, representative conditions may refer to when the core samples have been maintained at an elevated pressure and/or temperature that is/are representative of the original reservoir pressure and/or temperature, such that the fluids contained in the samples have not undergone a phase transition (e.g., at a bubble point or dew point) and the fluid contents of the samples remain representative of reservoir conditions. Additionally, in certain exemplary embodiments, representative conditions may refer to the structure of the samples having changed less than if the pressure and/or temperature had been allowed to reach ambient conditions. In some embodiments, a non-miscible fluid, such as a fluorocarbon, has been deployed surrounding the samples in the first vessel to further minimize changes to the composition of the fluids contained in the samples due to a pressure decrease from the reservoir to the surface.
The present invention may be better understood by reading the following description of non-limitative embodiments with reference to the attached drawings. In the interest of clarity, not all features of an actual implementation are described in this specification. One of ordinary skill in the art will appreciate that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.
In some embodiments, the core sample is retrieved from a wellbore from a subterranean reservoir using a rotary sidewall coring process. Moreover, in one embodiment, the core sample comprises a plurality of rock and fluid samples retrieved from various depths in a wellbore of a subterranean reservoir, for example, using a rotary sidewall coring process. However, it is possible to retrieve a single core sample with the rotary sidewall coring process. The core sample may comprise a sidewall core sample or practically any other core sample that may be retrieved from the subterranean reservoir.
In some embodiments, a single core sample may be at least 1 inch in length (e.g., at least 1.25 inches in length, at least 1.5 inches in length, or at least 1.75 inches in length). In some embodiments, a single core sample may be 2 inches or less in length (e.g., 1.75 inches or less in length, 1.5 inches or less in length, or 1.25 inches or less in length). The length of the single core sample may be in an amount ranging from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, a single core sample may be between 1 inch and 2 inches (e.g., between 1.25 inches and 2 inches or between 1.5 inches and 2 inches). In some embodiments, a single core sample may be any length less than 1 inch, although tests on such samples may yield a larger error than for samples having a length at least 1 inch.
The second vessel may include at least 1 core sample, and a plurality of core samples in an amount up to the capacity of the measurement zone or region of the second vessel. In some embodiments, the second vessel includes at least 2 core samples. In some embodiments, a plurality of core samples may include at least 5 core samples (e.g., at least 6 core samples, at least 7 core samples, at least 8 core samples, at least 9 core samples, at least 10 core samples, at least 11 core samples, at least 12 core samples, at least 13 core samples, or at least 14 core samples). In some embodiments, a plurality of core samples may include 15 core samples or less (e.g., 14 core samples or less, 13 core samples or less, 12 core samples or less, 11 core samples or less, 10 core samples or less, 9 core samples or less, 8 core samples or less, 7 core samples or less, or 6 core samples or less). The quantity of core samples in a plurality of core samples may be in an amount ranging from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, a plurality of core samples may include between 5 core samples and 15 core samples (e.g., between 5 core samples and 10 core samples, between 10 core samples and 12 core samples, between 10 core samples and 15 core samples, between 11 core samples and 15 core samples, or between 12 core samples and 15 core samples). As an example, the first vessel may contain 10-15 core samples with each core sample having a length of between 1 inch and 2 inches, and all of those core samples may be transferred from the first vessel to the second vessel.
Thus, those of ordinary skill in the art will appreciate that the term “core sample” may therefore include practically any core sample that may be transferred from the first vessel to the second vessel, such as, but not limited to, transferring a single core sample from the first vessel to the second vessel, transferring a plurality of core samples from the first vessel to the second vessel, transferring at least a portion of a core sample from the first vessel to the second vessel (e.g., via subsampling the core sample and transferring the subsample from the first vessel to the second vessel, or by transferring less than all core samples available in the first vessel to the second vessel such as leaving 9 core samples in the first vessel and only transferring 1 core sample from the first vessel to the second vessel), etc.
Turning to the vessels, in some embodiments, the test on the core sample is unable to be performed using the first vessel due to interference between the first vessel and equipment used for the test. For example, the first vessel comprises a magnetic material that may interfere with the test. For example, the first vessel comprises a metallic material that may interfere with the test. For example, the first vessel comprises magnetic and metallic material that may interfere with the test. However, in some embodiments, a measurement zone or region of the second vessel comprises a non-magnetic material such that the test may be performed. For example, the measurement zone of the second vessel comprises a non-metallic material such that the test may be performed. For example, the measurement zone of the second vessel may comprise non-magnetic and/or non-metallic material such that the test may be performed. In certain embodiments, the measurement zone of the second vessel is the region of the vessel and the volume contained within that region that may be measured by a test when the second vessel is appropriately placed in a test instrument. In certain embodiments, the measurement zone of the second vessel also includes the region of the vessel and the volume contained within that region that may influence a test, for instance, by negatively interfering with the test even when not directly measured when the second vessel is appropriately placed in a test instrument. In certain embodiments, the measurement zone of the second vessel is the region where the cores are housed within the second vessel. In certain embodiments, the measurement zone of the second vessel is the region where the cores are housed within the second vessel, in addition to about an inch away from the end cores. In certain exemplary embodiments, the measurement zone of the second vessel is the region where the cores are housed within the second vessel, in addition to about two inches away from the end cores.
In some embodiments, the non-magnetic material comprises a non-magnetic alloy, alumina, titanium, fiberglass, polyether ether ketone (PEEK), glass-fiber filled PEEK, a PEEK composite, polyphenylene sulfide (PPS), glass-fiber filled PPS, a PPS composite, polytetrafluoroethylene (PTFE), glass-fiber filled PTFE, a PTFE composite, a thermalplastic composite, a ceramic, or any combination thereof. In one embodiment, the second vessel (e.g., non-magnetic, non-metallic, or any combination thereof) is constructed of a thermoplastic liner and with a titanium endcap and titanium ball-valve flange interface. In one embodiment, the endcap and the interface are integrally wound to a fiber overwrap and are sealed with O-rings. As will be discussed further at 215, transferring the core sample from the first vessel to the second vessel allows the test to be performed on the core sample in the second vessel. Furthermore, the core sample is transferred while maintaining pressure and/or temperature, which may lead to test results more representative of reservoir conditions.
In one embodiment, the first vessel encloses the core sample in a sealed chamber at a pressure above ambient pressure. For example, the first vessel encloses the core sample at a pressure representative of a pressure from which the core sample was retrieved from the wellbore of the subterranean reservoir. In some embodiments, the first vessel encloses the core sample at a pressure of at least 100 psi (e.g., at least 200 psi, at least 300 psi, at least 400 psi, at least 500 psi, at least 600 psi, at least 700 psi, at least 800 psi, at least 900 psi, at least 1,000 psi, at least 1,500 psi, at least 2,000 psi, at least 2,500 psi, at least 3,000 psi, at least 3,500 psi, at least 4,000 psi, at least 4,500 psi, at least 5,000 psi, at least 5,500 psi, at least 6,000 psi, at least 6,500 psi, at least 7,000 psi, at least 7,500 psi, at least 8,000 psi, at least 8,500 psi, at least 9,000 psi, or at least 9,500 psi). In some embodiments, the first vessel encloses the core sample at a pressure of 10,000 psi or less (e.g., 9,500 psi or less, 9,000 psi or less, 8,500 psi or less, 8,000 psi or less, 7,500 psi or less, 7,000 psi or less, 6,500 psi or less, 6,000 psi or less, 5,500 psi or less, 5,000 psi or less, 4,500 psi or less, 4,000 psi or less, 3,500 psi or less, 3,000 psi or less, 2,500 psi or less, 2,000 psi or less, 1,500 psi or less, 1,000 psi or less, 900 psi or less, 800 psi or less, 700 psi or less, 600 psi or less, 500 psi or less, 400 psi or less, 300 psi or less, or 200 psi or less). In one embodiment, the range may go up to about 15,000 or 20,000 psi. In one embodiment, for example, for unconventional assets, the range of pressure may be 12,000-15,000 psi. The first vessel encloses the core sample at a pressure in an amount ranging from any of the minimum values described above to any of the maximum values described above. For example, the first vessel encloses the core sample at a pressure between 100 psi and 10,000 psi (e.g., between 1,000 psi and 10,000 psi, between 4,000 psi and 8,000 psi, between 2,000 psi and 6,000 psi, between 4,000 psi and 7,000 psi, or between 5,000 psi and 10, 000 psi).
The core sample is maintained at a substantially equivalent pressure or placed under a higher pressure during the transfer of the core sample from the first vessel to the second vessel. “Higher pressure” refers to 1%-5% in one embodiment, 5%-10% in another embodiment, 1%-10% in another embodiment, 1%-15% in another embodiment, 1%-20% in another embodiment, or 1%-25% in another embodiment. For example, at least one pressure measurement apparatus (e.g., pressure sensor or gauge) associated with the first vessel may be utilized to determine the pressure associated with the first vessel. Similarly, at least one pressure measurement apparatus (e.g., pressure sensor or gauge) associated with the second vessel may be utilized to determine the pressure associated with the second vessel. The pressure associated with the first vessel may be utilized to set or adjust the pressure associated with the second vessel such that the core sample is maintained at a substantially equivalent pressure or placed under a higher pressure during the transfer of the core sample from the first vessel to the second vessel.
Furthermore, in one embodiment, the core sample is maintained at a substantially equivalent temperature or higher temperature during the transfer of the core sample from the first vessel to the second vessel. “Higher temperature” refers to 1%-5% in one embodiment, 5%-10% in another embodiment, 1%-10% in another embodiment, 1%-15% in another embodiment, 1%-20% in another embodiment, or 1%-25% in another embodiment. In some embodiments, the temperature is at least 100 degrees Fahrenheit (e.g., at least 150 degrees Fahrenheit, at least 200 degrees Fahrenheit, at least 250 degrees Fahrenheit, at least 300 degrees Fahrenheit, or at least 350 degrees Fahrenheit). In some embodiments, the temperature is 400 degrees Fahrenheit or less (e.g., 350 degrees Fahrenheit or less, 300 degrees Fahrenheit or less, 250 degrees Fahrenheit or less, 200 degrees Fahrenheit or less, or 150 degrees Fahrenheit or less). The temperature can be present in an amount ranging from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, the temperature can be between 100 degrees Fahrenheit and 400 degrees Fahrenheit (e.g., between 150 degrees Fahrenheit and 350 degrees Fahrenheit, between 200 degrees Fahrenheit and 400 degrees Fahrenheit, between 300 degrees Fahrenheit and 400 degrees Fahrenheit, or between 250 degrees Fahrenheit and 400 degrees Fahrenheit).
For example, at least one temperature measurement apparatus (e.g., temperature sensor or gauge) associated with the first vessel may be utilized to determine the temperature associated with the first vessel. Similarly, at least one temperature measurement apparatus (e.g., temperature sensor or gauge) associated with the second vessel may be utilized to determine the temperature associated with the second vessel. The temperature associated with the first vessel may be utilized to set or adjust the temperature associated with the second vessel such that the core sample is maintained at a substantially equivalent temperature or higher temperature during the transfer of the core sample from the first vessel to the second vessel.
Turning to the transfer, as described previously with respect to
In some embodiments, the entire contents of the first vessel may be transferred to the second vessel while maintaining pressure and/or temperature. In some embodiments, less than the entire contents of the first vessel may be transferred to the second vessel while maintaining pressure and/or temperature. In some embodiments, the second vessel may receive the transferred core sample from the first vessel. For example, a single core sample can be transferred to the second vessel. For example, a plurality of core samples from a single first vessel (e.g., a single first vessel of a coring tool) can each be transferred to individual second vessels, in several groups to multiple second vessels, or all to a single second vessel. The multiple second vessels might each be designed for different tests or laboratory measurements, or they may be compatible with multiple tests or measurements. As a plurality of core samples are taken from a single subsurface zone of interest in order to minimize cross-contamination of varying fluid compositions, it may not be necessary to perform the same test or measurement on multiple core samples from the same zone.
At 210, the method 200 optionally includes using a non-hydrogenated fluid during the transfer of the core sample from the first vessel to the second vessel. In some embodiments, a non-hydrogenated fluid preserves the core sample in the first vessel. In some embodiments, a non-hydrogenated fluid preserves the core sample in the second vessel. In some embodiments, the non-hydrogenated fluid comprises a fluorocarbon.
At 215, the method 200 includes performing a test on the core sample in the measurement zone of the second vessel. For example, the second vessel having the core sample may be inserted into an apparatus (e.g., a nuclear magnetic resonance (NMR) spectrometer) and a test may be performed on the core sample.
In one embodiment, the test performed on the core sample comprises a magnetic resonance test. In one embodiment, the magnetic resonance test comprises NMR. In one embodiment, the magnetic resonance test comprises magnetic resonance imagining (MRI). In one embodiment, the magnetic resonance test comprises NMR and MRI.
NMR testing is discussed further in the following items: (a) U.S. Pat. No. 10,228,336 (Atty. Dkt. No. T-9935), (b) U.S. Pat. No. 10,145,810 (Atty. Dkt. No. T-10017), (c) U.S. Patent App. Pub. No. 2017/0030845 (Atty. Dkt. No. T-10177), (d) U.S. Patent App. Pub. No. 2017/0285215 (Atty. Dkt. No. T-10368), (e) Chen, Z., Singer, P. M., Wang, X., Hirasaki, G. J., & Vinegar, H. J. (2019, June 15). Evaluation of Light Hydrocarbon Composition, Pore Size, and Tortuosity in Organic-Rich Chalks Using NMR Core Analysis and Logging. Society of Petrophysicists and Well-Log Analysts. SPWLA 60th Annual Logging Symposium, Jun. 15-19, 2019, (f) Sakuraf, S., Loucks, R. G., & Gardner, J. S. (1995 Jan. 1). Nmr Core Analysis Of Lower San Andres/Glorieta/Upper Clear Fork (Permian) Carbonates: Central Basin Platform, West Texas. Society of Petrophysicists and Well-Log Analysts. SPWLA 36th Annual Logging Symposium, pages 1-12, Jun. 26-29, 1995, and (g) Shafer, J. (2013 Dec. 1). Recent Advances in Core Analysis. Society of Petrophysicists and Well-Log Analysts. SPWLA-2013-v54n6-A4, (b) Unalmiser, S., & Funk, J. J. (1998 Apr. 1). Engineering Core Analysis. Society of Petroleum Engineers. SPE-36780-JPT, each of which is incorporated by reference. However, those of ordinary skill in the art will appreciate that practically any magnetic resonance test known to those of ordinary skill in the art may be performed on the core sample.
MRI testing is discussed further in the following items: (a) Robinson, M. A., Deans, H. A., & Bansal, S. (1992 Jan. 1). Determination of Oil Core Flow Velocities and Porosities Using MRI. Society of Petroleum Engineers. SPE-23960-MS, (b) Cano-Barrita, P. F. de S., Balcom, B. J., Green, D., McAloon, M., & Dick, J. (2008 Jan. 1). Capillary Pressure Measurement in Petroleum Reservoir Cores with MM. Offshore Technology Conference. OTC 19234, and (c) Denney, T. (2008 Aug. 1). Capillary Pressure Measurement on Cores by MRI. Society of Petroleum Engineers. 0808-0063-PT SPE, pages 63-66, each of which is incorporated by reference. However, those of ordinary skill in the art will appreciate that practically any magnetic resonance test known to those of ordinary skill in the art may be performed on the core sample.
In one embodiment, the test performed on the core sample comprises a computed tomography (CT) test. CT testing is discussed further in the following items: (a) Hidajat, I., Mohanty, K. K., Flaum, M., & Hirasaki, G. (2004 Oct. 1). Study of Vuggy Carbonates Using NMR and X-Ray CT Scanning. Society of Petroleum Engineers. SPE 88995-PA, (b) Closmann, P. J., & Vinegar, H. J. (1993 Sep. 1). A Technique For Measuring Steam And Water Relative Permeabilities At Residual Oil In Natural Cores: CT Scan Saturations. Petroleum Society of Canada. JCPT93-09-08, and (c) Arns, C. H., Sakellariou, A., Senden, T. J., Sheppard, A. P., Sok, R. M., Knackstedt, M. A., Bunn, G. F. (2003 Jan. 1). Virtual Core Laboratory: Properties of Reservoir Rock Derived From X-ray CT Images. Society of Exploration Geophysicists, SEG-2003-1477, each of which is incorporated by reference. However, those of ordinary skill in the art will appreciate that practically any computed tomography test known to those of ordinary skill in the art may be performed on the core sample.
In one embodiment, the test performed on the core sample comprises a neutron test. Neutron testing is discussed further in the following items: (a) Jasti, J. K., Lindsay, J. T., & Fogler, H. S. (1987 Jan. 1). Flow Imaging in Porous Media Using Neutron Radiography. Society of Petroleum Engineers. doi:10.2118/16950-MS, SPE 16950 and (b) Nicholls, C. I., & Heaviside, J. (1988 Mar. 1). Gamma-Ray-Absorption Techniques Improve Analysis of Core Displacement Tests. Society of Petroleum Engineers. SPE 14421-PA. each of which is incorporated by reference. Those of ordinary skill in the art will appreciate that practically any neutron test known to those of ordinary skill in the art may be performed on the core sample.
In one embodiment, the test performed on the core sample comprises an acoustic test. In one embodiment, the acoustic test comprises acoustic resonance technology (ART) or acoustic resonance (AR). Acoustic testing is discussed further in the following item: (a) Sivaraman, A., Hu, Y. F., Thomas, F. B., Bennion, D. B., & Jammaluddin, A. K. M. (1998 Jan. 1). Determination of Phase Transitions In Porous Media Using Acoustic Technology. Petroleum Society of Canada. PETSOC-98-75, which is incorporated by reference. Those of ordinary skill in the art will appreciate that practically any acoustic test known to those of ordinary skill in the art may be performed on the core sample.
In one embodiment, the test performed on the core sample comprises a dielectric test. Dielectric testing is discussed further in the following items: (a) Leung, P. K., & Steig, R. P. (1992 Jan. 1). Dielectric Constant Measurements: A New, Rapid Method To Characterize Shale at the Wellsite. Society of Petroleum Engineers. IADC/SPE 23887-MS and (b) Ali A. Garrouch, (2018), “Predicting the cation exchange capacity of reservoir rocks from complex dielectric permittivity measurements,” GEOPHYSICS, Volume 83, Issue 1, MR1-MR14 (January 2018), each of which is incorporated by reference. Those of ordinary skill in the art will appreciate that practically any dielectric test known to those of ordinary skill in the art may be performed on the core sample.
In one embodiment, the test performed on the core sample comprises a magnetic resonance test, a computed tomography test, a neutron test, an acoustic test, a dielectric test, or any combination thereof. Those of ordinary skill in the art will appreciate that this is not an exhaustive list, and at least one test not listed herein may be performed in one embodiment. For example, in some embodiments, the test(s) discussed in the following item may be utilized: Aidan Blount, et al, “Maintaining and Reconstructing In-Situ Saturations: A Comparison Between Whole Core, Sidewall Core, and Pressurized Sidewall Core in the Permian Basin,” Petrophysics 60, 50-60 (2019), which is incorporated by reference.
The test results may be utilized in a variety of ways, as discussed hereinbelow at 220, 225, 230, 235, 240, 245, 250, or any combination thereof.
At 220, the method 200 includes determining (e.g., determining, measuring, etc.) a fluid saturation of the core sample using the test. For example, the tests discussed herein may be utilized to analyze the fluid composition of the core sample that has remained at elevated pressure and/or elevated temperature during retrieval from the subterranean reservoir to the laboratory. For example, one or more of the tests may be utilized for petrophysical analysis to determine the fluid saturation of the subterranean reservoir as a function of depth—in other words, the identity and relative amount of fluids present in the pore volume, including liquid hydrocarbons, water, and gas (hydrocarbon and otherwise)—in order to identify the optimal zone(s) for economic production of hydrocarbons. Those of ordinary skill in the art will appreciate that the test results may be utilized to determine the fluid saturation of the core sample.
Fluid saturations are conventionally determined using one or more laboratory samples that have already undergone compositional changes from their native state. However, in some embodiments the pressure and/or temperature of the first vessel has been maintained at representative conditions during retrieval from the reservoir in order to minimize or eliminate structural changes to the sample and/or phase or composition changes to the fluids contained in the sample. Additionally, as disclosed herein, the core sample is maintained at a substantially equivalent pressure or placed under a higher pressure during the transfer of the core sample from the first vessel to the second vessel. Moreover, in some embodiments, the core sample is maintained at a substantially equivalent temperature or higher temperature during the transfer of the core sample from the first vessel to the second vessel. By doing so, compositional changes in the core sample may be reduced (or completely avoided) and the core sample may be closer to its native state during testing in the second vessel, which may lead to more accurate test results.
At 225, the method 200 optionally includes calibrating test measurements on at least one other core sample performed at ambient pressure using the determined fluid saturation. For example, the observed changes can be analyzed to create a calibration for standard laboratory measurements performed at ambient pressure on regular core samples (i.e., core samples that have not maintained pressure and/or temperature) taken from the same subterranean reservoir, so that the determined fluid saturation can be related to the probable native fluid saturation in the subterranean reservoir. Extraction of pressure-preserved core samples is expected to be significantly more expensive than standard (not pressure-preserving) coring services, so it is beneficial to primarily collect regular core samples with only a few pressure-preserved core samples for calibration. This process enhances the accuracy of the core-to-log calibration for laboratory measurements performed on the regular core samples, and therefore, ultimately the accuracy of the reservoir models used to make business decisions about which reservoirs to produce for oil and/or gas.
At 230, the method 200 optionally includes reducing the pressure on the core sample in the second vessel; and repeating the test on the core sample in the second vessel. For example, the pressure of the core sample may be reduced, step by step, to ambient pressure.
At 235, the method 200 optionally includes reducing the temperature on the core sample in the second vessel; and repeating the test on the core sample in the second vessel. For example, the temperature of the core sample may be reduced, step by step, to ambient temperature.
In one embodiment, the pressure only is reduced (at 230). In one embodiment, the temperature only is reduced (at 235). In one embodiment, the pressure and temperature are reduced. As another example, reduction of pressure may occur, reducing in multiple steps may occur, with test measurements in between may occur. Those of ordinary skill in the art will appreciate that many options are possible.
At 240, the method 200 optionally includes injecting a chemical agent (e.g., fluorocarbon) into the second vessel to preserve fluid saturation of the core sample to allow for testing of the core sample at ambient pressure conditions outside the second vessel. For example, the preservation may not affect geomechanical properties of the core sample.
At 245, the method 200 optionally includes cooling the core sample in the second vessel to preserve fluid saturation of the core sample to allow for testing of the core sample at ambient pressure conditions outside the second vessel. For example, the preservation may not affect geomechanical properties of the core sample.
At 250, the method 200 optionally includes injecting a chemical agent (e.g., a resin, a polymer, an alloy, or any combination thereof) into the second vessel to encase the core sample to preserve fluid saturation of the core sample to allow for testing of the core sample at ambient pressure conditions outside the second vessel. For example, a resin, a polymer, an alloy, or any combination thereof may be selected so that they do not affect geomechanical properties of the core sample.
EXAMPLE: A NMR example will now be discussed, and a similar approach may be utilized with the other tests. NMR is utilized for measuring saturation, and NMR distinguishes between fluids based on differences in parameters of the detected magnetic resonance signals, including signal relaxation times (referred to as T1 and T2) and measured diffusion coefficients. Different excitation and measurement sequences are employed to enable sensitivity to these parameters, and they are optimized for the expected values in a given reservoir. NMR data may be represented as 1-, 2-, or 3-dimensional spectra, where the axes can represent values of T1 and T2 relaxation times and diffusion coefficients. Downhole NMR logging tools can provide saturation values with spatial resolution on the order of one or several feet of depth, but NMR log data is best calibrated against laboratory measurements performed under both as-received and controlled saturation conditions, using typically 5 to 30 core samples per well.
All measurements described in this example involve first transferring the core samples from a first vessel of a commercial coring tool at elevated pressure to a second vessel(s) that is designed to be compatible with the measurement technologies intended for use with those core samples, while maintaining pressure. In certain embodiments, such as in the case of NMR measurements, this may involve designing the second vessel to contain only non-magnetic components and designing the measurement zone of the second vessel to contain only non-metallic and low/no noise components. The coring tool may also contain at least one non-hydrogenated fluid, such as a fluorocarbon, which may be chosen to be both non-wetting on the rock material and non-miscible with hydrocarbons and water, and thus assist in maintaining the fluid saturations within the core samples. The non-hydrogenated fluid can also be transferred to the second vessel without interfering with hydrogen NMR measurements. Core samples from a single coring tool can each be transferred to individual second vessels, in several groups to multiple second vessels, or all to a single second vessel. The multiple second vessels might each be designed for different laboratory measurements or tests, or they may be compatible with multiple measurements or tests. As a plurality of core samples are taken from a single subsurface zone of interest in order to minimize cross-contamination of varying fluid compositions, it may not be necessary to perform the same test or measurement on multiple core samples from the same zone.
NMR measurements can be performed on the core sample(s) at the initial pressure and/or temperature, then at intermediate pressure values and/or temperature values as the second vessel is depressurized. The NMR data can be used to determine the fluid saturations at each step. The observed changes can be analyzed to create a calibration for standard laboratory measurements performed at ambient pressure on regular core samples (i.e., samples not extracted by a tool that preserves pressure) taken from the same formation, so that the measured fluid saturation can be related to the probable native fluid saturation in the subterranean reservoir. Extraction of pressure-preserved core samples is expected to be significantly more expensive than standard (not pressure-preserving) coring services, so it is beneficial to primarily collect regular core samples with only a few pressure-preserved core samples for calibration. This process enhances the accuracy of the core-to-log calibration for laboratory measurements performed on the regular core samples, and therefore ultimately the accuracy of the reservoir models used to make business decisions about which reservoirs to produce for oil and/or gas.
NMR spectrometers are available in a range of magnetic field strengths (and some have variable field strength), with different field strengths offering advantages and disadvantages depending on the intended application. It is customary to describe an instrument in terms of its proton magnetic resonance frequency, which is directly proportional to the field strength (the constant of proportionality is the proton gyromagnetic ratio, 42.6 MHz/Tesla). For example, NMR logging tools are generally in the range of 500 kHz-2 MHz, and laboratory NMR devices used for log calibration are typically at around 2 MHz, with systems in the range of 10-20 MHz becoming more common for tight rock unconventional samples. For purposes of determining fluid saturations, instruments at particular field strengths may be advantageous for discriminating between certain fluid types.
In some embodiments, the field strength is at least 0.5 MHz (e.g., at least 1 MHz, at least 10 MHz, at least 20 MHz, at least 30 MHz, at least 40 MHz, at least 50 MHz, at least 60 MHz, at least 70 MHz, at least 80 MHz, or at least 90 MHz). In some embodiments, the field strength is 100 MHz or less (e.g., 90 MHz or less, 80 MHz or less, 70 MHz or less, 60 MHz or less, 50 MHz or less, 40 MHz or less, 30 MHz or less, 20 MHz or less, or 10 MHz or less). The magnetic field strength can be present in an amount ranging from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, the magnetic field strength may be between 0.5 MHz and 100 MHz (e.g., between 0.5 and 4 MHz, between 4 and 20 MHz, between 20 and 60 MHz, or between 60-100 MHz). In some embodiments, the magnetic field strength of any commercially available NMR spectrometer may be utilized (e.g., up to 1.2 GHz). In some embodiments, magnetic field strengths of approximately 2 MHz and 42 MHz may be utilized. Although data from one measurement frequency may be sufficient, comparing the NMR data at these two frequencies may aid in determining fluid saturations in the core samples. These values are determined by the instruments available in our laboratory, and they may not be optimal for the fluids present in a particular reservoir. The ideal measurement frequencies for particular rock and/or fluid types (such as in the unconventional area) is a subject of ongoing research, so tests may be applied using instruments with other values of the NMR measurement frequencies, or using a different number of measurement frequencies.
NMR spectra, in particular those that include T1 and/or T2 axes, can be used to characterize the sizes and types of pores in a sample, and the fluids contained therein (both quantity and kind). For example, in a shale sample, the NMR spectrum can distinguish between organic and inorganic pores. In a core sample from a conventional reservoir (such as a carbonate or sandstone), the NMR spectrum can be related to the distribution of pore sizes present. Clay-bound and/or capillary-bound fluids can also be distinguished from free fluid. As a core sample is depressurized, measured changes in the NMR spectrum can be analyzed to determine changes in the fluid saturations of different subsets of pores in the sample, such as different pore types or different pore sizes.
Precise chemical compositions of the fluids in these pore subsets can be determined by also performing geochemical analysis (such as gas chromatography) on the gases released from the core samples, and subsequently expelled from the second vessel, at each depressurization step. The observed sequence of chemicals identified at each pressure, and the corresponding changes in the NMR spectrum, describe the particular fluids expected to be recovered as the pressure drops in a reservoir during production, including in what pressure range each fluid will be recovered and from which pores.
Although the total quantity of fluid produced is of interest, and potentially the quantities of particular kinds of fluids (such as hydrocarbons in general, or particular kinds of hydrocarbon), it is not necessarily viable to completely deplete an individual reservoir during production. The methods described here can therefore be used to characterize well productivity in specific pressure ranges. The rate of depressurization can also be varied between samples, in order to study how the depletion rate affects the ultimate productivity of a particular reservoir. NMR and/or geochemistry can be performed as the depletion progresses, in order to quantify how the depletion rate affects which fluids are expelled at a given pressure, and from which pores. This information can be used to optimize aspects of the production design, such as the pressure depletion window and the depletion rate (set for instance by the choke size at the wellhead). Studying how to optimize the depletion rate for total productivity can also lead to an improved estimate of ultimate recovery (EUR), which is a metric for reserves booking.
The physical phases of the individual fluids may change during depressurization, if those fluids pass through phase boundaries (such as at the dew and/or bubble points) at a given temperature. This phase behavior cannot be easily predicted or measured in some systems, such as nanoscale pores in shale, but systems and methods for using NMR to observe and characterize phase behavior and measure phase boundaries in such systems, as in U.S. Pat. No. 10,634,746, which is incorporated by reference, may be used. The methods described there can be applied to the pressurized core samples described in this disclosure. For example, as the pressure is reduced, a change in some NMR parameter associated with a particular fluid (such as T2) may indicate a change in the phase of that fluid. As discussed herein, the native fluids present in the core sample, rather than loading a fluid into the sample in the laboratory and then pressurizing, may be advantageous because the measurements would be more readily applicable to the specific rock/fluid system of a particular reservoir.
These NMR methods can also be applied using magnetic resonance imaging (MRI) techniques, which allow for 1-D, 2-D, and/or 3-D spatial imaging of various NMR parameters, such as fluid quantities (e.g., total and/or effective porosity) or relaxation parameters (T1, T2). Different regions of a sample may contain different fluid saturations, or they may exhibit different saturation changes or phase behavior as a function of pressure, all of which could be measured and imaged using MM. Physical changes to the rock during depressurization, such as fracturing or other damage, can also be observed by MRI. These changes can be correlated with the fluid saturations and pore properties present in the sample, or in the specific regions of the sample where the changes occur.
Samples can also be imaged using CT methodologies (which may require different second vessel designs), which typically can have finer spatial resolution than MRI but less sensitivity to fluid saturation, and the images correlated with the NMR and/or MM measurements. For example, CT images may be used to monitor the orientation of fractures, both those present in a sample as received and those induced during depressurization. In addition, MRI and/or CT can be used to determine the sizes and positions of individual samples in a second vessel containing multiple samples, in case the second vessel is opaque to visible light or other imaging methods.
In contrast to existing tools and methodologies, embodiments consistent with this disclosure may allow measurement of in-situ water saturations and the salinity of the pore water/original reservoir brine, two parameters that are important for reservoir characterization. Furthermore, embodiments consistent with this disclosure can potentially be used to measure relative permeability under more accurate conditions. The embodiments consistent with this disclosure may allow determination of effective porosity at in-situ reservoir conditions.
All methods discussed here can also be applied to study samples as the temperature is decreased in steps to ambient temperature, potentially in combination with decreases in pressure (either simultaneous or sequential). In addition, NMR/MRI can also characterize temperature-dependent changes in fluid viscosity, wettability, asphaltene precipitation, and wax precipitation.
MODIFICATIONS: Those of ordinary skill in the art will appreciate that various modifications may be made to the embodiments provided herein. For example, one embodiment may involve transferring at least a portion of a core sample from the first vessel to a plurality of vessels. The core sample is maintained at a substantially equivalent pressure or placed under a higher pressure during the transfer of the core sample from the first vessel to the plurality of vessels. Furthermore, in one embodiment, the core sample is maintained at a substantially equivalent temperature or higher temperature during the transfer of the core sample from the first vessel to the plurality of vessels.
Claims
1. A method of performing a test on a core sample, the method comprising:
- transferring at least a portion of a core sample from a first vessel to a second vessel, wherein the core sample is maintained at a substantially equivalent pressure or placed under a higher pressure during the transfer of the core sample from the first vessel to the second vessel; and
- performing a test on the core sample in the second vessel.
2. The method of claim 1, wherein the test on the core sample is unable to be performed using the first vessel due to interference between the first vessel and equipment used for the test.
3. The method of claim 1, wherein the core sample comprises one or more selected from the group consisting of: rock and fluid samples retrieved from a wellbore of a subterranean reservoir using a rotary sidewall coring process, a plurality of rock and fluid samples retrieved from various depths in a wellbore of a subterranean reservoir using a rotary sidewall coring process, and rock and fluid retrieved from a wellbore of a subterranean reservoir using a pressure coring process.
4. The method of claim 1, wherein the first vessel encloses the core sample in a sealed chamber at a pressure above ambient pressure.
5. The method of claim 4, wherein the core sample is enclosed within the first vessel, and wherein the core sample is maintained at a pressure representative of a pressure from which the core sample was retrieved from the subterranean reservoir.
6. The method of claim 1, wherein the first vessel comprises a magnetic material, a metallic material, or both; and wherein a measurement zone of the second vessel comprises a non-metallic material, non-magnetic material, or both.
7. The method of claim 6, wherein the non-magnetic material comprises a non-magnetic alloy, alumina, titanium, fiberglass, polyether ether ketone (PEEK), glass-fiber filled PEEK, a PEEK composite, polyphenylene sulfide (PPS), glass-fiber filled PPS, a PPS composite, polytetrafluoroethylene (PTFE), glass-fiber filled PTFE, a PTFE composite, a thermalplastic composite, a ceramic, or any combination thereof.
8. The method of claim 1, wherein the core sample is maintained at a substantially equivalent temperature or higher temperature during the transfer of the core sample from the first vessel to the second vessel.
9. The method of claim 8, further comprising:
- reducing the temperature on the core sample in the second vessel; and
- repeating the test on the core sample in the second vessel.
10. The method of claim 1, wherein the test comprises a magnetic resonance test, a computed tomography test, a neutron test, an acoustic test, a dielectric test, or any combination thereof.
11. The method of claim 10, wherein the magnetic resonance test is performed at a plurality of measurement frequencies.
12. The method of claim 10, wherein the magnetic resonance test is used to determine at least one of a porosity of the core sample, a permeability of the core sample, a chemical composition of the core sample, a chemical shift of the core sample, a pore size distribution of the core sample, one or more molecular weights of any hydrocarbons contained within the core sample, relaxation times of the core sample, diffusion coefficients of the core sample, or any combinations thereof.
13. The method of claim 10, wherein the magnetic resonance test comprises a magnetic resonance imaging test.
14. The method of claim 1, further comprising:
- reducing the pressure on the core sample in the second vessel; and
- repeating the test on the core sample in the second vessel.
15. The method of claim 14, further comprising determining a change in the phase of a fluid contained in the core sample due to the reduction in pressure.
16. The method of claim 14, further comprising creating a model of hydrocarbon production as a function of pressure for the subterranean reservoir from which the core sample was retrieved.
17. The method of claim 16, further comprising determining the optimum depletion rate for the subterranean reservoir.
18. The method of claim 1, further comprising transferring at least a portion of a core sample from the first vessel to a plurality of vessels, wherein the core sample is maintained at a substantially equivalent pressure or placed under a higher pressure during the transfer of the core sample from the first vessel to the plurality of vessels.
19. The method of claim 1, further comprising using the test to determine one or more of the following: a fluid saturation of the core sample, a spatial distribution of fluid saturations within the core sample, a salinity of a brine contained in the core sample, and an effective porosity of the core sample.
20. The method of claim 19, further comprising calibrating test measurements on at least one other core sample performed at ambient pressure using the determined fluid saturation
21. The method of claim 1, further comprising injecting a chemical agent into the second vessel to preserve fluid saturation of the core sample to allow for testing of the core sample at ambient pressure conditions outside the second vessel.
22. The method of claim 1, further comprising cooling the core sample in the second vessel to preserve fluid saturation of the core sample to allow for testing of the core sample at ambient pressure conditions outside the second vessel.
23. The method of claim 1, wherein a non-hydrogenated fluid preserves the core sample in the first vessel, a non-hydrogenated fluid preserves the core sample in the second vessel, and a non-hydrogenated fluid is used during the transfer of the core sample from the first vessel to the second vessel.
24. The method of claim 23, wherein the non-hydrogenated fluid comprises a fluorocarbon.
25. The method of claim 1, wherein the second vessel comprises a measurement zone, wherein the measurement zone is constructed by wrapping a low or no noise resin and fiber material around a tube, wherein the tube is constructed from a non-metallic material, a non-magnetic material, or both.
Type: Application
Filed: Jul 31, 2020
Publication Date: Feb 4, 2021
Inventors: Scott Jeffrey Seltzer (Houston, TX), Marcus Oliver Wigand (Missouri City, TX), Zheng Yang (Katy, TX), Michael T. Rauschhuber (Houston, TX), Edward Russell Peacher (Cypress, TX), James Daniel Montoya (Santa Fe, NM)
Application Number: 16/944,654
