CA2917819A1

CA2917819A1 - Method and apparatus for quantitative measurement of hydrocarbon production with fluid imbibition

Info

Publication number: CA2917819A1
Application number: CA2917819A
Authority: CA
Inventors: Dean M. Willberg; Neil W. Bostrom; Maxim Andreevich Chertov; Markus Pagels
Original assignee: Schlumberger Canada Ltd
Current assignee: Schlumberger Canada Ltd
Priority date: 2013-08-06
Filing date: 2014-06-27
Publication date: 2015-02-12
Also published as: EP3030748A1; WO2015020735A1

Abstract

A method of characterizing hydrocarbon production from a core sample obtained from a reservoir includes saturating the core sample with at least one saturating fluid. A flow of an imbibing fluid is initiated across a surface of the saturated core sample with the core sample subjected to confining pressures and maintained at a controlled temperature. One or more properties (such as volume or pressure) of countercurrent flow of the saturating fluid and one or more properties (such as volume or pressure) of cocurrent flow of the saturating fluid is measured over time in response to the flow of the imbibing fluid. Characteristics of the core sample can be measured before and after exposure to the imbibing fluid to assess changes to the core sample.

Description

METHOD AND APPARATUS FOR QUANTITATIVE MEASUREMENT OF
HYDROCARBON PRODUCTION WITH FLUID IMBIBITION
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims priority from US Provisional Patent Application 61/862,831, filed August 6, 2013, which is incorporated herein by reference in its entirety.
BACKGROUND
Field

[0002] The following disclosure relates to methods and apparatus to measure gas production from a core sample of reservoir rock.
Related Art

[0003] Hydraulic fracturing can be used to stimulate production of hydrocarbon gas and liquids from reservoir rock (typically a mudstone or shale). Hydraulic fracturing injects a fracturing fluid (typically a mixture of water, proppants and chemicals) at high pressure into a wellbore to create small fractures in the reservoir rock formation, along which fluids such as hydrocarbon gas, petroleum, and possibly brine water may migrate to the well. During hydraulic fracturing, the liquid components of the fracturing fluid can imbibe into the reservoir rock formation and the hydrocarbons (i.e., gas and/or petroleum) that are trapped in the reservoir rock formation can be pushed by the fracturing fluid further into the reservoir rock formation (termed "cocurrent flow") or pushed by the fracturing fluid out of the reservoir rock formation into the fracture (termed "countercurrent flow"). Modeling of such cocurrent flow and countercurrent flow, if at all possible, is inefficient and would likely produce an overly complex model.
SUMMARY

[0004] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key

5 or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
[0005] Illustrative embodiments of the present disclosure are directed to a test method and a test apparatus. In a first aspect, a method of characterizing hydrocarbon production of a core sample includes saturating the core sample with a saturating hydrocarbon fluid and subsequent testing of the saturated core sample while controlling a confining pressure and temperature of the core sample at reservoir pressure and temperature conditions (i.e., pressure and temperature that are characteristic of the reservoir rock from which the core sample was extracted). The testing of the saturated core sample can include flowing an imbibing fluid across a surface of the saturated core sample and measuring at least one property (such as volume or pressure) of countercurrent flow of saturating hydrocarbon fluid and at least one property (such as volume or pressure) of cocurrent flow of the saturating hydrocarbon fluid over time in response to flow of the imbibing fluid across the core sample.

[0006] The core sample is a sample of reservoir rock extracted from a subterranean reservoir rock formation. The core sample can be removed from the reservoir rock with common coring tools, including a rotary coring bit, rotary sidewall coring tools, and explosive gun-type sidewall coring tools. In one embodiment, the core sample has a cylindrical form having two opposed end faces with a cylindrical sidewall that extends between the two opposed end faces. The core sample can be held by a core holder with opposed end caps and a flexible elastomeric sleeve sealed to the end caps and surrounding the cylindrical sidewall of the core sample. The confining pressure can be applied to the cylindrical sidewall of the core sample through the sleeve. The imbibing fluid can flow along a path that extends across one end face of the core sample. A
desired boundary condition can be applied to the other end face of the core sample, such as maintaining a constant pressure in a flowpath downstream from the other end face of the core sample or maintaining a constant volume in such downstream flowpath.

[0007] The method can be used to determine whether adsorbed hydrocarbon gas is being produced from the core sample or whether such gas is being trapped (i.e., bypassed) in the core sample as the imbibing fluid flows across the core sample when the saturating fluid is in the gas phase.

[0008] The pressure of the imbibing fluid can be controlled to be approximately equal to, greater than, or less than the reservoir pressure. The difference in pressure between the imbibing fluid and the saturating fluid simulates various stages to which the reservoir is subject. The imbibing fluid pressure equal to the saturating fluid pressure simulates the formation during closure. In this case the flow of imbibing fluid into the core sample is termed "spontaneous imbibition". The imbibing fluid pressure greater than the saturating fluid pressure simulates the formation during fracturing. In this case the flow of imbibing fluid is termed "imbibitions and leakoff'. The imbibing fluid pressure less than the saturating fluid pressure simulates the formation during production. The magnitude of the pressure difference can be specified according to the process the experiment is attempting to replicate.

[0009] In another aspect, a test apparatus for measurement of hydrocarbon fluid production from a core sample includes a first fluid pump that pumps a saturating hydrocarbon fluid to a core holder that contains the core sample and a second fluid pump that pumps imbibing fluid to the core holder. The core holder can provide for imbibing fluid supplied by the second pump to flow across a surface of the core sample.
The apparatus includes a countercurrent measurement device that measures quantity of the countercurrent flow of the saturating hydrocarbon fluid from the core holder and a cocurrent measurement device that measures at least a quantity of the cocurrent flow of the saturating hydrocarbon fluid from the core holder. The test apparatus can further include a vessel that encloses the core holder and that applies a desired confining pressure to the core sample contained in the core holder and that maintains the core sample contained in the core holder at a desired temperature. The test apparatus can also include a fluid pressure controller that controls pressure of the imbibing fluid flowing to the core holder at a desired pressure level.

[0010] In yet another aspect, a method of measuring steady state permeability of a core sample obtained from a reservoir includes saturating the core sample with a hydrocarbon fluid at reservoir conditions. The method also includes measuring a pressure differential between a first side and a second side of the saturated core sample while flowing the hydrocarbon fluid into the first side of the core sample.
The method also includes measuring a flow of the hydrocarbon fluid into the first side of the core sample and measuring a flow of hydrocarbon fluid out of the second side of the core sample, and determining the permeability of the core sample based on the flow measurements.

[0011] A more complete understanding will become apparent to those skilled in the art upon reference to the detailed description taken in conjunction with the provided figures.
BRIEF DESCRIPTION OF THE DRAWINGS

[0012] Fig. lA is a schematic view of a core holder assembly showing fluid flow through the core holder assembly during a test procedure in accordance with an aspect of the present disclosure.

[0013] Fig. 1B is a schematic view of a core holder assembly according to an embodiment of the present disclosure.

[0014] Fig. 1C is a view of one side of a distribution plug for use in the core holder assembly shown in Fig. 1B.

[0015] Fig. 2 is a schematic diagram of a test measurement apparatus that employs the core holder assembly of Fig. 1B in accordance with an aspect of the present disclosure.

[0016] Figs. 3A and 3B are graphs showing countercurrent hydrocarbon gas production measurements obtained using the test measurement apparatus shown in Fig. 2.

[0017] Fig. 4 is a graph showing cocurrent and countercurrent hydrocarbon gas production measurements obtained using the test measurement apparatus shown in Fig. 2.

[0018] Fig. 5 is a graph showing cocurrent and countercurrent hydrocarbon gas production measurements and measurements of water imbibing into the core sample that are obtained using the test measurement apparatus shown in Fig. 2.

[0019] Fig. 6A is a graph showing cocurrent and countercurrent hydrocarbon gas production measurements obtained using the test measurement apparatus shown in Fig. 2 for testing performed when the imbibing fluid pressure is above the saturating pressure of the hydrocarbon gas that saturates the core sample.

[0020] Fig. 6B is a graph showing the hydrocarbon gas production measurements obtained using the test measurement apparatus shown in Fig. 2 for testing performed when the imbibing fluid pressure is below the saturating pressure of the hydrocarbon gas that saturates the core sample and the core sample was exposed to the imbibed fluid seen in Fig. 6A.

[0021] Fig. 7 is a graph showing water content and strength of the core sample from testing performed when imbibing fluid is allowed to enter the core sample.

[0022] Fig. 8 is a flow chart of a method of determining whether adsorbed hydrocarbon gas is being produced from a core sample or is being retained in the core sample.
DETAILED DESCRIPTION

[0023] Illustrative embodiments of the present disclosure are described below. In the interest of clarity, not all features of an actual implementation are described in this specification. It will be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions can be made to achieve the developer's 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. Further, like reference numbers and designations in the various drawings indicate like elements.

[0024] For the purposes of this disclosure, the term "hydrocarbon fluid"
means a fluid that includes one or more hydrocarbon components, such as alkanes (e.g., methane), napthenes, aromatics, and asphaltenes.

[0025] Moreover, for the purposes of this disclosure, the term "saturating hydrocarbon fluid" means a hydrocarbon fluid that saturates a core sample during test operations as described herein.

[0026] Moreover, for the purposes of this disclosure, the term "imbibing fluid" means a fluid that flows across a surface of a core sample and into the core sample during testing operations as described herein.

[0027] Fig. lA is a schematic showing a core holder assembly that includes a core holder 101 and a core sample 102, which is a sample of rock extracted from a subterranean reservoir rock formation. The core sample 102 can be removed from the reservoir rock with common coring tools, including a rotary coring bit, rotary sidewall coring tools, and explosive gun-type sidewall coring tools. Typically, the core sample 102 is prepared as a cylinder having dimensions of about 1.5 inches (38 mm) long and about 1.5 inches (38 mm) in diameter. The core sample 102 can be weighed and measured and can be qualified with X-ray tomography and pulse decay permeability to confirm a lack of fractures or high permeability streaks. Tests are performed on the core sample 102 on an 'as received' basis as described hereinbelow to determine properties of the core sample 102 that are representative of the rock formation from which the core sample 102 was taken. Alternatively, the tested core sample may be dried or saturated.

[0028] The flow of an imbibing fluid (such as water) and a saturating hydrocarbon fluid (such as methane gas ¨ CH4) that saturates the core sample 102 during one or more of the tests described herein are schematically depicted in Fig. 1A. The imbibing fluid is controlled to flow across a first end 108 (which can be referred to herein as the fracture side or end face) of the core sample 102. The first end 108 is disposed opposite a second end 110 (which can be referred to herein as the formation side or end face) of the core sample 102. With the controlled flow of the imbibing fluid across the first end 108 of the core sample 102, a desired boundary condition can be applied to the second end 110 of the core sample 102. For example, the boundary condition can maintain a constant pressure in a flowpath downstream from the second end 110 of the core sample 102 or can maintain a constant volume in such downstream flowpath. The imbibing fluid that flows across the first end 108 of the core sample 102 can enter the core sample 102 through imbibition, due to capillary pressure, and/or through leakoff into the bulk of the core sample 102 due to a pressure gradient across the core sample 102. The flow of the imbibing fluid due to imbibition and leakoff is shown schematically as arrow 112. The leakoff of the imbibing fluid can cause desorption and/or displacement of the saturating hydrocarbon fluid towards the second end 110 of the core sample 102, which is referred to as cocurrent flow. Alternatively, the leakoff of the imbibing fluid can cause desorption and displacement of the saturating hydrocarbon fluid towards the first end 108 of the core sample 102, which is referred to as countercurrent flow. The cocurrent flow of the saturating hydrocarbon fluid is shown schematically as arrow 114. The countercurrent flow of the saturating hydrocarbon fluid is shown schematically as arrow 116.
The countercurrent flow of the saturating hydrocarbon fluid can be mixed with imbibing fluid that does not enter into and leakoff into the core sample as it flows across the first end 108 of the core sample 102.

[0029] Fig. 1B
illustrates a cross-sectional view of an embodiment of the core holder assembly 101 of Fig. 1A. In this embodiment, the core holder 101 includes a flexible elastomeric sleeve 151 disposed about the core sample 102 and sealably engaged to a first end cap 153 and to a second end cap 155. The end caps 153, 155 can be mechanically fixed and sealably engaged by seals 156 (e.g., o-ring seals) to a cylindrical housing 157 that defines an annular region 159 disposed between the inner surface of the housing 157 and the outer surface of the sleeve 151. Pressurized fluid can be supplied to the annular region 159 via passageways 161 through the housing 157. The pressurized fluid contained within the annular region 159 can exert a radial confining pressure on the core sample 102 via the flexible sleeve 151 as desired. The first end cap 153 can support a distribution plug 163 such that the distribution plug 163 floats relative to the first end cap 153 and the housing 157. A seal 164 (e.g., o-ring seal) can seal the interface between the distribution plug 163 and the first end cap 153. A portion of the distribution plug 163 can extend axially beyond the first end cap 153 and sealably engage to the flexible sleeve 151 as shown. The distribution plug 163 includes an end surface 165 that is disposed adjacent the first end 108 of the core sample 102. The opposed second end 110 of the core sample 102 interfaces to an end surface 167 of the second end cap 155. The first end cap 153 and the distribution plug 163 define a region 169 that is disposed adjacent the distribution plug 163. The region 169 is fluidly coupled to the region 159 via passageways 171 through the first end cap 153 that extend between region 159 and region 169. In this configuration, the pressurized fluid that is supplied to region 159 can flow to and fill region 169 via passageways 171. The pressurized fluid contained within region 169 can exert an axial confining pressure on the core sample 102 via the distribution plug 163 as desired.

[0030] The first end cap 153 and the distribution plug 163 support and/or define two fluid flow lines 173, 175 that carry a flow of imbibing fluid that is supplied to and flows across the first end 108 of the core sample 102, which is operably disposed adjacent the end surface 165 of the distribution plug 163. Seals 176 (e.g., o-rings) can be used to seal the interface between the flow lines 173, 175 and the first end cap 153 if needed. Two fluid flow lines 177 and 180 are defined by the second end cap 155. The fluid flow lines 177 and 180 are in fluid communication with the second end 110 of the core sample 102 adjacent the end surface 167 of the second end cap 155.

[0031] A first end plug 178 is mechanically joined to the housing 157 by a threaded interface and can be configured to secure the first end cap 153 to the housing 157.
Similarly, a second end plug 179 is mechanically joined to the housing 157 by a threaded interface and can be configured to secure the second end cap 155 to the housing 157.

[0032] The core sample 102 can be loaded into the core holder assembly as shown by placing the core sample 102 through the loading end of the housing 157 (i.e., the end that holds the second end cap 155). In this case, the first end plug 178 secures the first end cap 153 and the distribution plug 163 in place inside the housing 157 and the sleeve 151 is secured to the first end cap 153 and to the distribution plug 163 inside the housing 157.
The core sample 102 is placed inside the sleeve 151. The second end cap 155 can then be engaged to the sleeve 151 and then secured in place to the housing 157 by threading the second end plug 179 into its threaded interface with the housing 157.

[0033] Fig. 1C shows details of an embodiment of the distribution plug 163 of Fig.
1B, which has an end surface 165 that faces and contacts the first end 108 of core sample 102. The end surface 165 has a spiral groove 181 formed therein. A first hole or port 183 is formed at one end of the groove 181 at or near the center of the end surface 165, while a second hole or port 185 is formed in the other end of the groove 181 near the periphery of the end surface 165. The first hole or port 183 is disposed at the terminus of the fluid flow line 173 such that it is part of the fluid flow line 173 through the distribution plug 163. The second hole or port 185 is disposed at the terminus of the fluid flow line 175 such that it is part of the fluid flow line 175 through the distribution plug 163. The distribution plug 163 also includes an annular side surface 187 that extends from the end surface 165. The side surface 187 can be configured to sealably engage to the flexible sleeve 151 of the core holder 101. In one embodiment, the groove 181 is constructed to minimize the volume between the first end 108 of the core sample 102 and the end surface 165 of the distribution plug 163, while still permitting imbibing fluid (e.g., water) to flow across the first end 108 of the core sample 102 and contact a large surface area of the first end 108 of the core sample 102.

[0034] Fig. 2 shows a schematic diagram of a measurement apparatus 200 fluidly coupled to the core holder assembly 101 of Figs. 1B and 1C. The apparatus 200 includes various tubing, valves, reservoirs, and pumps fluidly connected to the assembly, as described hereinbelow. The measurement apparatus 200 includes an electrically-controlled reservoir and pump 221 that is loaded with a quantity of imbibing fluid (such as water). The reservoir and pump 221 can be an electrically-controlled syringe pump, such as a syringe pump from the ISCO line available from Teledyne Technologies Inc. of Lincoln, Nebraska, USA. The pump 221 has an outlet that is fluidly coupled to a supply line 280, which is fluidly coupled to the fluid flow line 173 of the core holder 101. The pump 221 can be configured to flow the imbibing fluid through the supply line 280 and through the fluid flow line 173 such that it exits the first hole or port 183 of the

35 distribution plug 163 where it can flow in the groove 181 that extends across the first end 108 of the core sample 102.
[0035] The measurement apparatus 200 can also include a storage reservoir 233 of the imbibing fluid and a valve 201 that are fluidly coupled to the inlet of the pump 221 and used to supply the imbibing fluid to the pump 221. A valve 202 can be fluidly coupled to the outlet of the pump 221 between the pump 221 and the supply line 280. A
vacuum line 222 can be fluidly coupled between the pump 221 and the valve 202.
The vacuum line 222 includes a valve 211 that isolates the outlet of pump 221 from a vacuum source 223, which can, for example, include a vacuum pump or an eductor.

[0036] The measurement apparatus 200 also includes a pressure sensor 224 which is fluidly coupled to the outlet of the pump 221. The pressure sensor 224 can be configured to monitor fluid pressure of the imbibing fluid supplied to the core holder 101 via the supply line 280.

[0037] The measurement apparatus 200 also includes a countercurrent measurement device 226. The countercurrent measurement device 226 has an inlet that is fluidly coupled to a first collection line 281 via a valve 204 and a backpressure regulator 225.
The first collection line 281 is fluidly coupled to the fluid flow line 175 of the core holder 101, which carries the countercurrent flow of the saturating hydrocarbon fluid (e.g., methane) mixed with imbibing fluid (e.g., water) that does not enter into and leakoff into the core sample 102 as it flows across the first end 108 of the core sample 102. In one embodiment, the countercurrent measurement device 226 is an inverted burette, which can be configured to collect the countercurrent flow (e.g., methane gas) of the saturating hydrocarbon fluid that exits from the core holder 101 via the fluid flow line 175 and flows through the first collection line 281.

[0038] The measurement apparatus 200 includes an electrically-controlled reservoir and pump 230 that is loaded with a quantity of saturating hydrocarbon fluid, such as methane gas. The reservoir and pump 230 can be an electrically-controlled syringe pump, such as a syringe pump from the ISCO line available from Teledyne Technologies Inc. of Lincoln, Nebraska, USA. The pump 230 has an outlet that is fluidly coupled to line 282 via valve 206. Line 282 is fluidly coupled to the fluid flow line 180 of the core holder 101. A separate line 283 containing a valve 205 is fluidly coupled to line 177 of the core holder 101 to allow for purging. The pump 230 and valve 206 are configured to flow the saturating hydrocarbon fluid to the second end 110 of the core sample 102 in a first operational mode in order to saturate the core sample 102 with the saturating hydrocarbon fluid and to receive hydrocarbon fluid produced from the second end 110 of the core sample 102 in a second operational mode. The operational modes of the pump 230 and valve 206 can be selected based on the measurement type for which the apparatus 200 is configured.

[0039] The measurement apparatus 200 also includes a pressure sensor 229 which is fluidly connected to line 282. The pressure sensor 229 can be configured to monitor the pressure of saturating hydrocarbon fluid (e.g., methane gas) that flows in the line 282.

[0040] The measurement apparatus 200 can also include a storage reservoir 231 of the saturating hydrocarbon fluid and a valve 207 that are fluidly coupled to the inlet of the pump 230 and used to supply the saturating hydrocarbon fluid to the pump 230.

[0041] The measurement apparatus 200 can also include a line 232 and valves 208, 210 that are fluidly coupled between the first collection line 281 (upstream of valve 204) and the line 282 (on the side of the valve 206 opposite the pump 230). Lines 232 and valves 208 and 210 can be configured to fluidly couple line 282 to line 281 in order to flow saturating hydrocarbon fluid to the first end 108 of the core sample 102 and saturate the core sample 102 with the saturating hydrocarbon fluid during the first operational mode of the pump 230 and valve 206 as described above where the pump 230 flows the saturating hydrocarbon fluid to the second end 110 of the core sample 102.

[0042] In one embodiment, all of the flow lines of the test apparatus 200 (e.g., lines 222, 280, 281, 282, 232) are constructed of small diameter tubing (0.030 inch (0.76 mm) inner diameter) capable of withstanding a pressure of at least 15,000 psi (1055 kg/square cm). Such small diameter tubing can reduce residence time of fluids in the apparatus 200 and can improve sensitivity of the measurements made using the apparatus 200.

[0043] It should be noted that the apparatus 200 can include various measurement apparatus 226 to measure properties of the flows produced from the core sample while the imbibing fluid from pump 221 is flowing. For example, a number of electronic volume or mass detectors can be used for this purpose, including, but not limited to, a liquid receiver, a series of cold traps, and an accumulator. Also, in at least one embodiment, the selection of the measurement device 226 is based on the saturating hydrocarbon fluid, the imbibing fluid, and the quantities of each.
Additionally, the countercurrent flow measurement devices 226 can be used in conjunction with one or more electronic composition measurement devices, such as a gas chromatograph, mass spectrometer, or optical spectrometer that can sample directly from the flow stream for continuous measurements or from samples taken from the flow stream and analyzed at a later time for discrete measurements. The controller and/or computer processing system 245 includes control logic that interfaces to the electronic composition measurement devices via wired or wireless signal paths therebetween for control of the operation of the electronic composition measurement devices. In other embodiments, the pH, salt content, and/or carbon dioxide content of the fluid that exits the fluid flow line 175 of the core holder 101 can be monitored. In addition, the measurement devices employed to measure and characterize the countercurrent flow can be employed to measure and characterize the cocurrent flow in the line 282.

[0044] The valves 201, 202, 204, 206-208, and 210, the pumps 221 and 230, and the backpressure regulator 225 can be electrically controlled by a controller and/or a computer processing system 245 that is part of the apparatus 200. The controller and/or computer processing system 245 includes control logic that interfaces to the electrically-controlled reservoir and pumps 221 and 230 via wired or wireless signal paths therebetween for control of the operation of the pumps 221 and 230, that interfaces to the electrically-controlled valves 201, 202, 204, 206-208, and 210 via wired or wireless signal paths therebetween for control of the operation of the valves 201, 202, 204, 206-208, and 210, that interfaces to the backpressure regulator 225 via wired or wireless signal paths therebetween in order to provide backpressure control of imbibing fluid that flows in the supply lines 280 and 281, and that interfaces to the pressure sensors 224 and 229 via wired or wireless signal paths therebetween for pressure monitoring and recordation of pressure measurements during operation of the apparatus 200.
The control logic of the controller and/or computer processing system 245 (which can be embodied in software that is loaded from non-transient memory and executed in the computing platform of the computer processing system 245) can be configured to control the different parts of the apparatus 200 to carry out a sequence of operations (workflow) that characterizes properties related to countercurrent and cocurrent hydrocarbon production from a core sample as described below. The control logic can be configured by user input or a testing script or other suitable data structure, which is used to configure the controller or the computer processing system 245 in order to carry out control operations that are part of the workflow as described herein. For example, the user input or the testing script or other suitable data structure can specify parameters (such as pressures, flow rates, and temperatures) for such control operations of the workflow.

[0045] The operations begin by saturating the core sample 102 with saturating hydrocarbon fluid (e.g., methane gas) using the test apparatus 200. The core sample 102 is saturated with the saturating hydrocarbon fluid while the core sample 102 is maintained at reservoir conditions (i.e., reservoir pressure and temperature).
In one embodiment, the test apparatus 200 can be operated to saturate the core sample 102 with the saturating hydrocarbon fluid as follows. The core holder assembly 101 with the core sample 102 loaded therein is placed in a pressure and temperature controlled oil bath 122 (Figs. lA and 2) that applies a confinement pressure and a temperature that approximate the pressure and temperature of the rock formation from which the core sample 102 was taken, i.e., typically referred to as "reservoir conditions". The confinement pressure can be applied to the core sample 102 in both radial and axial directions and can be up to 15,000 psi (1055 kg/square cm). Subjecting the core sample 102 to such reservoir conditions tends to close any microfractures in the core sample 102. Valves 206, 208, and 210 are opened (with the other valves of apparatus 200 closed) and pump 230 is operated to flow the saturating hydrocarbon fluid through lines 282, 232, and 281 to both the first end 108 and the second end 110 of the core sample 102 in order to saturate the core sample 102 with the saturating hydrocarbon fluid. The pressure measured by the pressure sensor 229 can be monitored and used as feedback to control operation of the pump 230 so that the pressure of the saturating hydrocarbon fluid supplied to core sample 102 is at or close to the reservoir pressure. The saturation process is typically timed and can last for about 72 hours to ensure pressure equilibrium within the core sample 102.
The duration of such operations can be compared to a predetermined saturation time.
When the duration is less than or equal to the predetermined saturation time, the flow of the saturating hydrocarbon fluid from pump 230 continues. When the duration is greater than or equal to the predetermined saturation time, the flow of the saturating hydrocarbon fluid from pump 230 is discontinued and the saturation process ends.

[0046] Various measurements can be obtained using the testing apparatus 200. For example, once the core sample 102 is saturated, a steady state permeability measurement can be obtained by establishing a pressure differential across the core sample 102 using the saturating hydrocarbon fluid. In this case, valves 206 and 204 can be opened (with the other valves of apparatus 200 closed) while the pump 230 is controlled to supply the saturating hydrocarbon fluid at a predetermined volumetric flow rate to the second end 110 of the core sample 102 via the line 282. While the pump 230 is introducing the saturating hydrocarbon fluid to the second end 110 of the core sample 102, the saturating hydrocarbon fluid is eluted from the first end 108 of the core sample 102 and flows through the collection line 281 to the measurement device 226, which can be operated to obtain a volume measurement of the saturating hydrocarbon fluid eluted from the first end 108 of the core sample 102 over time. An average rate of eluted fluid flow can then be determined and the rate of flow of the saturating hydrocarbon fluid into and out of the core sample 102 can be used to determine the permeability of the core sample 102 by known methods such as pulse decay, pressure decay, and steady state methods.
The pulse decay method places a pressure gradient across the core sample 102 and monitors the decay of the pressure gradient. The pressure decay method changes the gas pressure and as the gas enters the pore space of the core sample 102 the pressure declines. The steady state method places a fixed flow into the core sample 102 and measures the pressure across the core sample.

[0047] The apparatus 200 can also be configured to obtain a pulse decay permeability measurement. In this case, with the core sample 102 saturated, valves 202 and 206 can be opened (with the other valves of apparatus 200 closed) and pump 230 controlled to introduce a pulse of high pressure saturating hydrocarbon fluid into the second end 110 of the core sample 102. Core sample 102 is then isolated from the excess volumes in the apparatus 200 by closing all valves of apparatus 200. Differential pressure sensor 228 measures the difference in pressure between lines 281 and 282. After the pulse of high pressure is introduced, the pressure in the line 282 will decay as the fluid diffuses into the core sample 102. The decay of pressure at the second end 110 is measured while the introduced hydrocarbon fluid moves through the core sample 102 and the pressure at the first end 108 will rise until pressure equilibrium is reached, as measured by pressure sensors 224 and 229. The decay of the pressure can be used to determine the permeability of the core sample 102.

[0048] Also, the apparatus 200 can be configured for cocurrent and countercurrent measurement testing. For example, with the core sample 102 saturated, valves 201, 202, 204, and 206 can be opened (with the other valves of apparatus 200 closed) and pump 221 controlled to purge the flow path through the supply line 280 to the fluid flow line 173 of the core holder 101 and from the fluid flow line 175 of the core holder to the collection line 281 with the imbibing fluid. The imbibing fluid that flows through the collection line 281 can be emptied into the measurement device 226 if desired.
In this case, the fluid pressure of the imbibing fluid that flows across the first end 108 of the core sample 102 is maintained at reservoir pressure by the back pressure regulator 225, and the pressure at the second end 110 of the core sample 102 is maintained at reservoir pressure by operation of the pump 230. After this flow path has been purged, the pump 221 is controlled to dispense the imbibing fluid into supply line 280, either continuously or in a series of pulses, for supply to the first end 108 of the core sample 102, and the second end 110 of the core sample is maintained at desired boundary conditions (such as at a constant reservoir pressure or at a constant volume) by operation of the pump 230.
The imbibing fluid flows along the spiral groove 181 of the distribution plug 163 in contact with the first end 108 of the core sample. During such flow, the imbibing fluid that contacts the core sample 102 can enter the core sample 102 and be retained therein (imbibition) or the imbibing fluid can flow and exit from the fluid flow line 175 of the core holder 101 and flow through the collection line 281 to the measurement device 226.
The fluid that is carried by the fluid flow line 175 from the core holder 101 and through the collection line 281 to the measurement device 226 can include countercurrent flow of the saturating hydrocarbon fluid, which is displaced by the imbibing fluid entering the first end 108 of the core sample 102. The measurement device 226 can be configured to measure one or more properties (such as volume) of such countercurrent flow produced by the imbibing fluid flow. In at least one embodiment, the one or more properties (such as volume) of the imbibing fluid that flows through the backpressure valve 225 and into the measurement device 226 is also measured. The flow of the imbibing fluid into the core sample 102 can also cause desorption and displacement of saturating hydrocarbon fluid resulting in cocurrent flow of the saturating hydrocarbon fluid, which flows out of flow line 180 of the core holder 101 and to line 282. One or more properties (such a volume) of such cocurrent flow can be measured based upon the operation of the pump 230 while it operates to maintain the desired boundary conditions at the second end 110 of the core sample 102. For example, the volume of such cocurrent flow can be measured from volume output of the pump 230 where the pump 230 is operated to maintain the second end 110 of the core sample 102 at a constant reservoir pressure. In another example, the volume of such cocurrent flow can be measured from the magnitude of the pressure increase of the pump 230 where the pump is operated to maintain the second end 110 of the core sample 102 at a constant volume. The flow rate of the imbibing fluid as supplied by the pump 221 can be controlled to maximize the residence time of the imbibing fluid in contact with the first end 108 of the core sample 102 and to maximize countercurrent flow exiting from the flow path 175 of the core holder 101. The volumes of the cocurrent and countercurrent production of the saturating hydrocarbon fluid can be measured over time during the testing operations while the imbibing fluid from pump 221 is flowing. The values for the volumes of the cocurrent and countercurrent production of the saturating hydrocarbon fluid gas can be adjusted to the pressure and temperature at the core face by using the known density changes with pressure and temperature.

[0049] Figs. 3A and 3B show countercurrent gas production test results for a first core sample, which was saturated with methane gas according to the saturation process described above. The first core sample was assembled in a first core sample assembly (such as assembly 101), which was fluidly connected to the test apparatus 200 in the arrangement shown in Fig. 2. During the testing of the first core sample, water was used as the imbibing fluid. During the testing of the first core sample, the pressure of water was controlled with the backpressure regulator 225 so that there was no pressure differential across the first core sample. As shown in Fig. 3A, about 0.045 milliliters of countercurrent gas production measured at the actual high pressure/high temperature condition was observed over a 70 hour test period. Fig. 3B shows the countercurrent gas production test data of Fig. 3A plotted to the square root of time, which, when so plotted, suggests a relatively stable (straight line) countercurrent gas production up to about 40 square root minutes, with a leveling off of production at that point.

[0050] Fig. 4 shows cocurrent and countercurrent gas production from the first core sample during the testing of Figs. 3A and 3B. For the first core sample, the cocurrent gas production over the same time period was approximately the same as the countercurrent gas production. The cocurrent gas production shows an induction period where a pressure wave is migrating across the first core sample.

[0051] Fig. 5 shows cocurrent and countercurrent gas production test data for a second core sample that is different from the first core sample. However, the second core sample was saturated and tested under the same conditions as the first core sample. The test results for the second core sample indicate that compared to the testing of the first core sample, the second core sample produces less countercurrent flow and more cocurrent flow, thereby indicating that those measurements are strongly dependent on the core sample tested.

[0052] Also, for the second core sample, at the conclusion of testing, the continuous water flow from pump 221 was discontinued to measure the quantity of water imbibed into the second core sample. The volume of water imbibed into the core sample during the test can be obtained indirectly by measuring the rate of fluid moving into the core sample 102 and extrapolating with the square root of time (a known dependence) to zero (Fig. 5). Further, the difference between the volume of water supplied by the pump 221 during the test (which can be derived from the flow rate of the pump 221) and the volume of the fluid that exits the fluid flow line 175 and flows through the collection line 281 during the test (which can be measured by the measurement device 226) may be equated to the volume of water imbibed into the second core sample. It will be appreciated that, if the total volume of the water imbibed into the core sample 102 over a certain time period is greater than the total volume of the saturating hydrocarbon fluid produced over this time period, it is an indication that the gas in the core sample 102 is being retained in the sample and is being compressed within the pore system of the core sample 102. Additionally, if the amount of water going into the core sample is less than the sum of the fluid produced, it is an indication that adsorbed gas is contributing to the gas production. If the amount of water entering the core sample is equal to the sum of the fluid produced, there is little or no gas trapped in the core sample or the amount is offset by the amount of gas desorbed from the core sample. The foregoing interpretation may be masked by the flow properties of the core sample. In Fig. 5 there is an induction period of 15 square root minutes while the flow gradients in the core sample stabilize.
Therefore, it is best to interpret the data at greater than 40 square root minutes.

[0053] In another test, a third core sample (different from the first and second core samples) is assembled into a core holder assembly that is fluidly coupled to the test apparatus 200 as described above, which is used to saturate the third core sample with methane gas. Water, as the imbibing fluid, is pumped by the pump 221 through the flow line 173 such that water flows across the first end 108 of the core sample 102 and exits the fluid flow line 175 and continues through the collection line 281 during the test.
However, in this particular test, the pressure of the pump 221 is controlled to be 500 psi (35.2 kg/square cm) higher than the saturating pressure used to saturate the third core sample. Fig. 6A shows cocurrent flow, countercurrent flow, and water imbibition and leakoff data versus the square root of time during this test.

[0054] Fig. 6A shows that during the first 5 square root minutes the amount of cocurrent flow is negligible due to an induction period seen in Figs. 4 and 5.
The countercurrent flow reaches its maximum in the first 20 square root minutes, although such flow is less than that for the first core sample (Fig. 4). At 37 square root minutes the continuous water flow from pump 221 was discontinued to measure the quantity of water imbibed into the third core sample. The volume of water imbibed into the third core sample 102 during the test can be obtained indirectly by measuring the rate of fluid flow entering the core sample 102 and extrapolating with the square root of time to zero. For the third core the amount of calculated water into the core sample is greater than the sum of the cocurrent and the countercurrent gas production. In this case some of the gas displaced in the core sample was trapped and compressed in the pore network.

[0055] In Fig. 6B, illustrating data from a continuation of the test illustrated in Fig.
6A, at about 106,000 seconds after the start of the test, pump 221 is controlled such that the pressure of the water is 500 psi (35.2 kg/square cm) below the saturating pressure.
These conditions simulate the production of fluids from the formation after hydraulic fracturing. After the water pressure was lowered at 106,000 seconds, about three hours was required for the pressure gradient inside the core sample to become favorable for gas production on first end 108 and for flow on second end 110 simulating the formation to reverse. The three hour delay in gas production was attributed to water blockage in the third core sample owing to the initial testing with the higher water pressure and to the redistribution of pressure inside the core sample. At the end of the three hour delay at 118,000 seconds gas production resumed. As shown in Fig. 6B, after gas production resumed the rate of gas flow on first end 108 stabilized. The flow rate on second end 110 also stabilized to a near constant value greater than the flow entering the core sample from first end 108, evidence that gas trapped in the pore network at time less than 106,000 seconds was being produced at first end 108.

[0056] The test apparatus 200 can be used with a variety of imbibing fluids and a variety of saturating hydrocarbon fluids. The fluids can comprise various compositions, in the aqueous, gaseous, liquid, or supercritical states. Testing can also be conducted with the test apparatus 200 by varying the imbibing fluid pressure to study various parameters. For example, in one case, the pressure of the imbibing fluid can be set above the reservoir pressure to study forced leakoff. In another case, the imbibing fluid pressure can be set close to the reservoir pressure to study spontaneous imbibition; and in yet another case, the imbibing fluid pressure can be set below the reservoir pressure to study gas production.

[0057] For tests where the saturating fluid includes a single hydrocarbon component such as, for example, methane gas, a volume or mass measurement of the methane gas flow is sufficient to characterize the methane gas production from a core sample. In one embodiment, the saturating fluid can be a multicomponent fluid, such as methane gas and a higher molecular weight oil component. For tests where the saturating fluid includes multiple hydrocarbon components, in addition to the amount of the flow produced, consideration can also be given to the molecular composition of the hydrocarbon mixture produced. A notable example where such testing can be useful is for testing of oil producing mudstones.

[0058] The following example will be described for an oil producing core sample. In this example, an oil producing core sample (i.e., a fourth core sample) was obtained from a reservoir rock formation and brought to the surface. Over time the fourth core sample lost some of the hydrocarbons that were in the core sample when it was in the reservoir, while a portion of the hydrocarbons remained in the core sample. To return the core sample to reservoir conditions, and to ready the core sample for testing in the test apparatus 200, the fourth core sample was assembled into a core sample assembly, such as assembly 101 described above. The core sample assembly with the fourth core sample loaded therein was then fluidly connected to the test apparatus 200, as described above and as shown in Fig. 2, and was saturated with a multicomponent gas while the core sample was confined in an oil bath at the temperature and pressure of the reservoir from which the fourth core sample was obtained. The saturating hydrocarbon fluid was a high pressure multicomponent gas tailored to the reservoir from which the fourth core sample was obtained. As the fourth core sample was saturated, the high pressure multicomponent gas and any soluble fluids remaining in the core sample diffused into one another.

[0059] Once the fourth core sample was saturated, water, as the imbibing fluid, was flowed across first end 108 of the fourth core sample 102 to begin production testing, as described above. When gas was produced from the fourth core sample during testing, some of the fluid originally in the fourth core sample was produced along with the saturating fluid (multicomponent gas). However, since multiple fluids were produced, the composition of these fluids was obtained to more fully characterize the hydrocarbon fluid production.

[0060] As noted above, various composition measurement arrangements and devices, such as chromatographs and spectrometers, can be used to characterize multicomponent fluids eluting from a core sample. It will be appreciated that one skilled in the art can perform composition measurements in many different ways depending on the exact composition of the produced fluid and the fluid flowing past the face of the core. For example, in one embodiment fluid eluted from the core sample can be collected at high pressure in an accumulator and a high pressure gas chromatograph can be used with a sampling valve to inject the fluid into the chromatograph to obtain fluid composition data. In another embodiment, an eluted fluid sample is passed through a solvent to collect some of the fluid, and the solvent and the eluent can be analyzed together on a gas chromatograph. In another embodiment, the eluting fluid flows across a solid phase extraction disc or through a thermal desorption tube, which collect some of the fluid to be analyzed as batch samples. Also, in yet another embodiment, the eluting fluid is passed through an oil, water, and gas separator and each constituent is measured. In another embodiment, the eluting fluid flows in a series of cold traps to collect portions of the sample based on the boiling point of the fluid and each portion of the fluid is subsequently measured. One skilled in the art could also combine one or more of the above techniques. For example, in one embodiment, the eluting fluid can be collected at high pressure in an accumulator and, later, the collected fluid can flow from the accumulator though a solvent to analyze the eluent and the solvent using a gas chromatograph.

[0061] At the completion of gas production testing, the core sample 102 can be removed from the core holder assembly 101, weighed and dissected by shaving off thin layers. For example, 20 mm of the first end 108 (i.e., fracture side) of the core sample 102 can be removed to obtain a water profile, and 6 mm of the second end 110 (i.e., formation side) can be removed to provide a dry baseline for comparison. A
measurement is taken of the unconfined compressive strength of each layer of the core sample 102. The unconfined compressive strength of the core sample 102 can be related to a water invasion profile of the core sample 102. The removed layers of the core sample 102 can be collected, placed in an enclosed tube, and the water inside the shavings extracted with methanol. The water in the methanol is then measured with Karl Fischer titration, as described in US Patent Application Publication 2012/0151998, which is incorporated herein by reference.

[0062] Fig. 7 is a graph showing unconfined compressive strength (UCS) and water content as a function of location along the length of a core sample 102 tested using the test apparatus 200. As shown in Fig. 7, the water content is higher on the side of the core sample that had water applied, i.e., the first end 108. Moreover, Fig. 7 shows that the side that had water applied (the first end 108) is also weaker (has lower unconfined compressive strength) than the side of the core sample that did not have water applied (i.e., the second end 110). Other analyses can be performed on the layers of the core sample 102 such as, but not limited to, oil extraction, salt extraction, surface area, and pore size distribution.

[0063] Fig. 8 is a flowchart of a method of determining whether adsorbed gas is being produced from a reservoir sample or is being bypassed and trapped in the reservoir sample. At 801 a core sample 102 is assembled into a core sample assembly 101 which is fluidly connected to test apparatus 200. At 803, the core sample 102 is saturated with a saturating fluid, which can be comprised of one or a plurality of hydrocarbon constituents, as described above. Also, the lines of the test apparatus 200 used for cocurrent production are purged at 803. At 805, the flow of imbibing fluid is initiated, such as the flow of water from pump 221 to the core sample 102, where the imbibing fluid flows across an end surface of the core sample 102. Once the flow of the imbibing fluid is initiated, production of the saturating fluid can occur owing to imbibition and leak off of water, as described above. At 807, the cocurrent and countercurrent flows of the saturating fluid produced as a result of the flow of imbibing fluid across the end surface of the core sample are determined. At 809, the volume of imbibing fluid imbibed into the core sample 102 is determined. At 811, a comparison is made between the volume of water imbibed into the core sample 102 as determined at 809 and the volumes of the cocurrent and countercurrent flows of the saturating fluid produced from the core sample 102. If the volume of water imbibed exceeds the volumes of the cocurrent and countercurrent flows (i.e., > at 811), then it is determined at 813 that saturating fluid (gas) is being bypassed and trapped in the core sample 102. If the volume of water imbibed is equal to the volumes of the cocurrent and countercurrent flows (i.e., = at 811), then it is determined at 815 that saturating fluid (gas) is not trapped and is being produced from the core sample 102. If the volume of water imbibed is less than the volumes of the cocurrent and countercurrent flows (i.e., < at 811), then it is determined at 815 that saturating fluid (gas) is being desorbed from the core sample 102. At 817 the process ends.

[0064] There have been described and illustrated herein several embodiments of a test apparatus and method of using the apparatus. While particular embodiments have been described, it is not intended that the claims be limited thereto, as it is intended that the claims be as broad in scope as the art will allow and that the specification be read likewise. Thus, while particular test results have been disclosed, it will be appreciated that other results from other testing may be obtained as well. In addition, while particular types of imbibing and saturating fluids have been disclosed, it will be understood that other fluids can be used as well. Moreover, while particular configurations have been disclosed in reference to production collection devices and gas composition measurement arrangements, it will be appreciated that other configurations could be used as well. It will therefore be appreciated by those skilled in the art that yet other modifications could be made to the provided embodiments without deviating from its scope as claimed.

Claims

What is claimed is:

1. A method of measuring fluid production of a core sample obtained from a reservoir, the core sample having opposed faces, the method comprising:
saturating the core sample with at least one saturating fluid at pressure and temperature conditions;
flowing an imbibing fluid across one of the faces of the saturated core sample;
and measuring at least one property of countercurrent flow of the saturating fluid and at least one property of cocurrent flow of the saturating fluid in response to the flow of the imbibing fluid.

2. The method according to claim 1, wherein:
the at least one property of the countercurrent flow is selected from the group consisting of volume, compositional constituents, pH, salt content, and carbon dioxide content; and the at least one property of the cocurrent flow is selected from the group consisting of volume, compositional constituents, pH, salt content, and carbon dioxide content.

3. The method according to claim 1, wherein the saturating fluid comprises a single hydrocarbon component or multiple hydrocarbon components.

4. The method according to claim 1, wherein the imbibing fluid comprises water.

5. The method according to claim 1, further comprising:
measuring volume of the imbibing fluid flowing into the core sample; and measuring volume of the imbibing fluid flowing from the core sample.

6. The method according to claim 1, further comprising determining a quantity of the imbibing fluid in the core sample.

7. The method according to claim 6, further comprising:
comparing the quantity of imbibing fluid in the core sample with the sum of the quantities of the cocurrent flow and the countercurrent flow; and using the results of the comparing to determine whether the saturating fluid is being produced from the core sample or whether the saturating fluid is being retained in the core sample as the imbibing fluid flows across the saturated core sample.

8. The method according to claim 7, wherein:
when the quantity of imbibing fluid in the core sample is greater than the sum of the quantities of the cocurrent flow and the countercurrent flow, it is determined that the saturating fluid is being retained in the core sample as the imbibing fluid flows into the saturated core sample;
when the quantity of imbibing fluid in the core sample is equal to the sum of the quantities of the cocurrent flow and the countercurrent flow, it is determined that the saturating fluid is being produced from the core sample as the imbibing fluid flows into the saturated core sample; and when the quantity of imbibing fluid in the core sample is less than the sum of the quantities of the cocurrent flow and the countercurrent flow, it is determined that the saturating fluid is being desorbed from the core sample as the imbibing fluid flows into the saturated core sample.

9. The method according to claim 1, wherein the imbibing fluid is an incompressible fluid that is immiscible in the saturating fluid.

10. The method according to claim 1, further comprising dissecting the core sample by shaving layers from at least one of the opposed faces.

11. The method according to claim 10, further comprising measuring the unconfined compressive strength of each layer.

12. The method according to claim 10, further comprising measuring the imbibing fluid content of each layer.

13. The method according to claim 10, further comprising performing an analysis of each layer wherein the analysis is selected from the group consisting of oil extraction, salt extraction, surface area, and pore size distribution.

14. A test apparatus for measurement of hydrocarbon fluid production of a core sample obtained from a reservoir, the apparatus comprising:
a vessel configured to maintain a predetermined confining pressure on the core sample in a core sample assembly and to maintain a predetermined temperature of the core sample in the core sample assembly;

an imbibing fluid pump configured to pump imbibing fluid to the core sample assembly containing the core sample;
a countercurrent measurement device configured to measure at least one property of countercurrent hydrocarbon fluid flow from the core sample assembly;
a cocurrent measurement device configured to measure at least one property of cocurrent hydrocarbon fluid flow from the core sample assembly; and a fluid pressure controller configured to maintain a boundary condition of the imbibing fluid flowing to the core sample assembly.

15. The test apparatus according to claim 14, wherein the core sample assembly includes a first end cap at a first end of the core sample, a second end cap at a second end of the core sample opposite the first end, and an elastomeric member that surrounds the core sample and is sealed to the first and second end caps.

16. The test apparatus according to claim 15, wherein the countercurrent measurement device is fluidly coupled to the first end cap and the cocurrent measurement device is fluidly coupled to the second end cap.

17. The test apparatus according to claim 14, wherein the fluid pressure controller is a backpressure regulator.

18. The test apparatus according to claim 15, further comprising:
a first pressure sensor configured to measure pressure of the imbibing fluid supplied to the first end of the core sample; and a second pressure sensor configured to measure fluid pressure at the second end of the core sample.

19. The test apparatus according to claim 15, further comprising a differential pressure sensor to measure the pressure difference between the first and the second ends of the core sample.

20. The test apparatus according to claim 18, further comprising:
a first valve downstream of the first pressure sensor;
a second valve upstream of the second pressure sensor; and a source of high pressure saturation fluid fluidly coupled to the second valve, wherein the second valve is configured to open for a time duration to permit a volume of the high pressure saturation fluid to flow to the second end of the core sample and to close after the time duration.

21. The test apparatus according to claim 14, wherein the cocurrent measurement device includes a pump.

22. The test apparatus according to claim 14, wherein:
the at least one property of the countercurrent hydrocarbon fluid flow is selected from the group consisting of volume, compositional constituents, pH, salt content, and carbon dioxide content; and the at least one property of the cocurrent hydrocarbon fluid flow is selected from the group consisting of volume, compositional constituents, pH, salt content, and carbon dioxide content.

23. The test apparatus according to claim 14, further comprising an imbibing fluid measurement device configured to measure quantity of the imbibing fluid flowing from the first end cap.

24. A method of measuring permeability of a core sample obtained from a reservoir, the method comprising:
saturating the core sample with at least one saturating fluid at pressure and temperature conditions approximating the pressure and temperature conditions of the reservoir;
measuring a pressure differential between a first side and a second side of the core sample;
flowing the saturating fluid into the first side of the core sample to establish a pressure differential between the first side and the second side of the core sample;
measuring a flow of the saturating fluid into the first side of the core sample and measuring a flow of the saturating fluid out of the second side of the core sample; and determining a permeability of the core sample based on the flow measurements.