CA3000261C - Apparatuses, systems and methods for evaluating imbibition effects of waterflooding in tight oil reservoirs - Google Patents

Abstract

A method for evaluating imbibition effects of waterflooding on crude oil produced from at least two core samples is described herein. The method includes providing the at least two core samples to a core holder, each core sample forming a layer within the core holder, each core sample being absorbed with crude oil that is distinguishable from other crude oil absorbed on other core samples, and each core sample having a permeability that is different than a permeability of the other core samples, conducting the waterflooding on the core samples by injecting a first fluid into the core holder to produce a second fluid, the second fluid comprising at least a portion of the crude oil of each of the core samples; analyzing the second fluid to determine a volume of one portion of the crude oil produced from one of the core samples; and determining, based on the volume of the one portion of the crude oil, a volume of crude oil produced due to imbibition effects from the one of the core samples based on the permeability the one of the core samples.

Description

Apparatuses, Systems and Methods for Evaluating Imbibition Effects of Waterflooding in Tight Oil Reservoirs Technical Field [0001] The embodiments disclosed herein relate to waterflooding in oil reservoirs, and, in particular to apparatuses, systems and methods for evaluating imbibition effects of waterflooding in tight oil reservoirs.
Background

[0002] Primary recovery is typically the first stage of oil and gas production in which natural reservoir drives, such as the natural pressure of the reservoir, are used to recover hydrocarbons. For instance, in one example of primary recovery, hydrocarbons are driven towards the well and to the surface due to the pressure difference between the crude oil reservoir and the bottom of the well. Only a portion of the total crude oil present in a reservoir can be recovered during a primary recovery process.

[0003] Secondary recovery techniques are used to force additional oil beyond that recovered during primary recovery out of the reservoir. The simplest secondary recovery technique is direct replacement of crude oil in the reservoir with another medium in the form of a displacement fluid (also referred to as an injection fluid), usually water or gas. "Waterflooding", as it is called, requires water to be injected under pressure into reservoir rock formations via injection wells. The injected water acts to help maintain reservoir pressure, and sweeps the displaced oil ahead of it through the rock towards production wells from which the oil is recovered.

[0004] Tight oil is light crude oil that is contained in petroleum-bearing formations of low permeability such as but not limited to shale and sandstone. While conducting waterflooding in tight oil reservoirs, the volume of crude oil produced is impacted by water drive effects in relative high permeability layers and imbibition effects in relative low permeability payzones. Many researchers have therefore found that imbibition effects are a key mechanism for the development of tight oil reservoirs where their extremely low porosity and permeability have historically presented many development =

challenges. However, previous experimental studies of imbibition effects in the development of tight oil reservoirs have typically been conducted using regular cores under ambient pressures. These experimental conditions vary from the conditions present in natural reservoirs featuring high and low permeability layers and, accordingly, the lab results from these experiments do not accurately evaluate imbibition effects on production performances for tight oil reservoirs with properties of high-temperature, high-pressure and heterogeneous payzones.

[0005] With researchers in academia and industry increasingly turning their attention to oil extraction from tight oil reservoirs, there is a need for systems and methods for evaluating imbibition effects of waterflooding in tight oil reservoirs.
Summary

[0006] According to some embodiments, a method for determining imbibition effects of waterflooding on crude oil produced from at least two core samples, the method including providing the at least two core samples to a core holder, each core sample forming a layer within the core holder, each core sample being absorbed with crude oil that is distinguishable from other crude oil absorbed on other core samples, and each core sample having a permeability that is different than a permeability of the other core samples; conducting the waterflooding on the core samples by injecting a first fluid into the core holder to produce a second fluid, the second fluid comprising at least a portion of the crude oil of each of the core samples; analyzing the second fluid to determine a volume of one portion of the crude oil produced from one of the core samples; and determining, based on the volume of the one portion of the crude oil, a volume of crude oil produced due to imbibition effects from the one of the core samples based on the permeability the one of the core samples.

[0007] According to some embodiments, the first fluid is injected into the core sample having the highest permeability relative to the other core samples.

[0008] According to some embodiments, the crude oil of at least one of the core samples is saturated with a tracer to be distinguishable from the other crude oil absorbed on the other core samples.

[0009] According to some embodiments, the providing the at least two core samples is providing three core samples.

[0010] According to some embodiments, a temperature of the core holder is in a range of about 0 C to about 177 C.

[0011] According to some embodiments, a pressure of the core holder is in a range of about 0 kPa to about 34473 kPa.

[0012] According to some embodiments, the tracer is one of a dye and an oleic fluorescein tracer.

[0013] According to some embodiments, an apparatus for evaluating imbibition effects of waterflooding on crude oil produced from at least two core samples is provided, the apparatus including a body including a first end; a second end spaced apart from the first end; a volume defined by an inner wall of the body, the volume extending between the first end and the second end and housing the at least two core samples, each core sample forming a layer within the body of the core holder, each core sample being absorbed with crude oil that is distinguishable from other crude oil absorbed on other core samples, and each core sample having a permeability that is different than a permeability of the other core samples; an inlet disposed at the first end for receiving a first fluid for conducting the waterflooding; and an outlet disposed at the second end for removing a second fluid produced by the waterflooding, the second fluid comprising at least a portion of the crude oil of each of the core samples.

[0014] According to some embodiments, the inlet is configured to direct the fluid into the core sample with the highest permeability relative to the other core samples.

[0015] According to some embodiments, the outlet is configured to receive the fluid from the core sample with the highest permeability relative to the other core samples.

[0016] According to some embodiments, the crude oil of at least one of the core samples is saturated with a tracer to be distinguishable from the other crude oil absorbed on the other core samples.

[0017] According to some embodiments, a system for conducting a core flooding test is provided, the system including an apparatus for determining imbibition effects of waterflooding on crude oil produced from at least two core samples, the apparatus including a body including a first end spaced apart from a second end to define a volume therebetween, the volume housing the at least two core samples, each core sample forming a layer within the body of the core holder, each core sample being absorbed with crude oil that is distinguishable from other crude oil absorbed on other core samples, and each core sample having a permeability that is different than a permeability of the other core samples; an inlet disposed at the first end for receiving a first fluid for conducting the waterflooding; and an outlet disposed at the second end for removing a second fluid produced by the waterflooding, the second fluid comprising at least a portion of the crude oil of each of the core samples; and an analyzer coupled to the apparatus and configured to: analyze the second fluid to determine a volume of one portion of the crude oil produced from one of the core samples; and determine, based on the volume of the one portion of the crude oil, a volume of crude oil produced due to imbibition effects from the one of the core samples based on the permeability the one of the core samples.

[0018] According to some embodiments, the inlet is configured to direct the fluid into the core sample with the highest permeability relative to the other core samples.

[0019] According to some embodiments, the outlet is configured to receive the fluid from the core sample with the highest permeability relative to the other core samples.

[0020] According to some embodiments, the crude oil of at least one of the core samples is saturated with a tracer to be distinguishable from the other crude oil absorbed on the other core samples.

[0021] Other aspects and features will become apparent, to those ordinarily skilled in the art, upon review of the following description of some exemplary embodiments.
Brief Description of the Drawings

[0022] The drawings included herewith are for illustrating various examples of articles, methods, and apparatuses of the present specification. In the drawings:

[0023] FIG. 1 is a perspective view of a core holder, according to one embodiment;

[0024] FIG. 2 is a top view of the core holder shown in FIG. 1;

[0025] FIG. 3 is an end view of the core holder shown in FIG. 1;

[0026] FIG. 4 is a partial cross-section view of a schematic of the core holder of FIG. 1;

[0027] FIG. 5 is an exploded side view of the core holder of FIG. 1 showing each of the internal parts;

[0028] FIG. 6 is an end perspective view of an artificial core, according to one embodiment;

[0029] FIG. 7 is a top view of the artificial core of FIG. 6 in an overlapping configuration;

[0030] FIG. 8 is a top view of the artificial core of FIG. 6 in a spaced configuration;

[0031] FIG. 9 is a perspective view of a core sleeve, according to one embodiment;

[0032] FIG. 10 is a top view of the core sleeve of FIG. 9;

[0033] FIG. 11 is a perspective view of a distributor for use with a core holder, according to one embodiment;

[0034] FIG. 12 is an end view of the distributor of FIG. 11;

[0035] FIG. 13 is a graph showing an interpretation diagram of hue value versus volume percentage of yellow dye in a crude oil sample;

[0036] FIG. 14 is a method of saturating at least one core sample for core flooding testing, according to one embodiment;

[0037] FIG. 15 is a method of saturating at least one core sample for core flooding testing, according to another embodiment;

[0038] FIG. 16 is a sample configuration for combining core samples saturated with oil treated with tracers, according to one embodiment;

[0039] FIG. 17 is a second sample configuration for combining core samples saturated with oil treated with tracers, according to an embodiment;

[0040] FIG. 18 is a third sample configuration for combining core samples saturated with oil treated with tracers, according to an embodiment;

[0041] FIG. 19 is a fourth sample configuration for combining core samples saturated with oil treated with tracers, according to an embodiment;

[0042] FIG. 20 is a schematic diagram showing a simulation model for studying the imbibition contribution;

[0043] FIG. 21 is a graph comparing calculated and experimental oil recoveries;

[0044] FIG. 22 is a graph showing oil rates of scenarios that consider imbibition;

[0045] FIG. 23 is a graph showing oil rates of scenarios that do not consider imbibition; and

[0046] FIG. 24 is a graph showing oil rates for cores having differing permeabilities.
Detailed Description

[0047] Various systems and methods will be described below to provide an example of each claimed embodiment. No embodiment described below limits any claimed embodiment and any claimed embodiment may cover apparatuses, systems and methods that differ from those described below. The claimed embodiments are not limited to apparatuses, systems and methods having all of the features of any one apparatus, system and method described below or to features common to multiple or all of the apparatuses, systems and methods described below.

[0048] Terms of degree such as "about" and "approximately" as used herein mean a reasonable amount of deviation of the modified term such that the end result is not significantly changed. These terms of degree should be construed as including a deviation of at least 5% or at least 10% of the modified term if this deviation would not negate the meaning of the word it modifies.

[0049] The term "comprising" and its derivatives, as used herein, are intended to be open ended terms that specify the presence of the stated features, elements, components, groups, integers, and/or steps, but do not exclude the presence of other unstated features, elements, components, groups, integers and/or steps. The foregoing also applies to words having similar meanings such as the terms, "including", "having"
and their derivatives.

[0050] The term "consisting" and its derivatives, as used herein, are intended to be closed terms that specify the presence of the stated features, elements, components, groups, integers, and/or steps, but exclude the presence of other unstated features, elements, components, groups, integers and/or steps.

[0051] The term "consisting essentially of", as used herein, is intended to specify the presence of the stated features, elements, components, groups, integers, and/or steps as well as those that do not materially affect the basic and novel characteristic(s) of features, elements, components, groups, integers, and/or steps.

[0052] The apparatuses, systems and methods described herein may provide apparatuses, systems and methods for evaluating the contribution of imbibition effects on the oil production in heterogeneous tight oil reservoirs under high temperature ¨ high pressure (HTHP) conditions during waterflooding processes and may enhance the understanding of waterflooding mechanisms in a heterogeneous oil reservoir.

[0053] In an attempt to mimic waterflooding process in heterogeneous tight oil reservoirs, the apparatuses, systems and methods described herein describe conducting a waterflooding test where crude oil extraction from multiple (e.g.
at least two) core samples is measured in parallel within a single core holder. This parallel-core flooding test can be used to study oil extraction from natural core samples with varying permeabilities where the natural core samples have been extracted from a target tight formation oil well (e.g. from adjacent layers of the target tight formation oil well). The parallel-core flooding test can be used to study oil extraction from artificial core samples having similar physical properties (e.g. porosity, permeability, etc.) as the target tight formation oil well (e.g. as adjacent layers of the target tight formation oil well).

[0054] To study the contributions of imbibition effects on oil extraction during waterflooding in core samples with varying permeabilities, the apparatuses, systems and methods described herein propose, in some embodiments, to use tracers such as dye tracers (e.g. red or green dyes) and/or oleic fluorescein tracers (e.g.
with different color or different molecular structures) to trace crude oil extracted from different core samples (e.g. from different layers) during waterflooding. Core samples having varying permeabilities may be positioned within different layers of the core holder during the waterflooding test, each core sample saturated with a different tracer. For instance, tracers used during the waterflooding tests may vary in color or fluorescence in order to trace crude oil from different layers of the core holder. A quantity of crude oil produced (e.g. exiting the core holder) may be monitored (e.g. in real-time) during the waterflooding process. Following this, producing mechanisms of different core layers can be evaluated based on crude oil production volume from different layers as determined based on the presence of the tracers in the produced fluid.
Core Holder

[0055] Referring to Figures 1 to 3, illustrated therein are perspective, top and front views, respectively, of a body 102 of a core holder 100 for conducting core flooding tests, according to one embodiment. Body 102 has a first end 104 spaced apart from a second end 106 to define a volume 108 therebetween. Volume 108 is sized and shaped to hold a core sample 132 (see Figure 4) therein for use in core flooding tests. Core holder 100 has a first opening 110 at first end 104 and a second opening (not shown) at second end 106 to provide for insertion and/or removal of the at least one core sample 132 into the volume 108, as described below. Core holder 100 optionally has first and second attachment mechanisms 116 and 118, respectively. Body 102 of core holder 100 may be formed, for example, from stainless steel

[0056] Figure 4 shows a partial cross-sectional view of the core holder 100 in an assembled configuration, according to one embodiment. Core holder 100 comprises a sleeve 126 housing one or more core samples 132. Distributors 130 are positioned on either side of the one or more core samples 132 to evenly distribute fluid (e.g. water) therethrough. Spacers 128 are positioned adjacent to the distributors 130 and are flanked by, end caps 124 and end plugs 120, respectively. Figure 5 shows an exploded side view of the core holder 100 of FIG. 4, according to one embodiment.

[0057] Core sample 132 is housed in sleeve 126. A distributor 130 is positioned on each end of core sample 132 within sleeve 126 to distribute water (or another water-based fluid) injected into the core sample 132 via tube 122 to conduct the waterflooding tests and to collect the fluid produced by the waterflooding tests. One or more spacers 128 are also inserted into sleeve 126 to stabilize core sample 132 and distributors 130 within sleeve 126. End caps 124 insert into each end of sleeve 126. Each end cap 124 threadingly engages body 102 to support sleeve 126 within body 102. End plugs then insert into and threadingly engage each end cap 124 to seal the core holder 100.
Confining pressure ports 134 provide a pathway for injecting a fluid into a space between an inner surface 136 of body 102 and an outer surface 138 of sleeve 126 to apply a pressure to the core sample 132 to mimic natural reservoir conditions.
Tube 122 extends from the external environment through the core holder 100 to the distributor 130 to carry water (or another water-based fluid) to core sample 132. Once the water or water-based fluid passes through the core sample 132, a second tube (not shown) extends from another distributor 130a to the external environment through the core holder 100 to carry produced fluid from the distributor 130 to the external environment.

[0058] As described further below, core holder 100 can be used with either natural core samples (e.g. samples collected from a target oil well) or artificial core samples (as described below) for conducting core flooding tests. In some embodiments, three core samples of varying permeabilities (i.e. mimicking different layers of tight oil reservoirs) can be disposed in distinct layers and inserted into sleeve 126 to evaluate imbibition effects of waterflooding on tight oil reservoirs.
Core Sample 132 . ,

[0059] Referring to Figures 6 to 8, illustrated therein is a core sample 132, according to one embodiment. In some embodiments, core sample 132 may comprise one or more core samples taken from one or more hydrocarbon bearing formations (e.g.
a well bore) of a reservoir that is under investigation, or from an outcrop rock having similar physical and chemical characteristics to the formation rock of the reservoir under investigation. For example, natural core samples to be compared using the systems, methods and apparatuses described herein can be taken from adjacent layers of a well bore to assess whether differences in rock characteristics (e.g. permeability) across the reservoir have an impact on waterflooding.

[0060] Alternatively or additionally, core sample 132 may comprise one or more artificial core samples that mimic natural core samples from a tight oil reservoir. For instance, core sample 132 may comprise sandpacks, preferably formed from produced sand; packs of ion exchange resin particles (either cationic or anionic exchange resins) that are designed to mimic ion exchange between injection fluids (in particular, injection waters) and the rock surface at the reservoir scale; packs of hydrophilic or hydrophobic resin particles (that are designed to mimic hydrophilic or hydrophobic surface of the formation rock); synthetic rock (e.g. silica); zeolites; or ceramic materials.
Clays (for example a kaolinite, smectite, pyrophyllite, illite, chorite or glauconite type clay) may be mixed with a sand prior to forming a sandpack. Clays may also be deposited onto sandpacks or onto synthetic rock samples. For example, cemented quartz may be bound with calcite and clays may then be deposited onto the surface of the synthetic rock.

[0061] Core sample 132 may be arranged to have one or more layers.
Hereinafter, core sample 132 may be referred to as having layers or as comprising individual core samples. For instance, as shown in Figures 6 to 8, core sample 132 may comprise a first layer 602 and a second layer 604 that are sized and shaped to fit within sleeve 126 of core holder 100. Alternatively, first layer 602 and second layer 604 may be referred to as separate core samples.

[0062] Core sample 132 may be sized (e.g. diameter, shape, length, etc.) based on the dimensions of core holder 100 and/or sleeve 126. For example, the cross section , ., of core sample 132 could be circular, square or rectangular, or any other suitable shape. In the examples shown in Figures 6 to 8, first layer 602 and second layer 604 complement each other to provide core sample 132 with a cylindrical shape that conforms to the interior of sleeve 126. Each layer of core sample 132 (e.g.
first layer 602 and second layer 604) may have a different permeability. Further, each layer of core sample 132 may have a different thickness. When using more than one layers to form core sample 132, the layers (e.g. first layer 602 and second layer 604) will generally have varying permeabilities to mimic the conditions of different layers in a target oil reservoir.

[0063] Referring now to Figures 7 and 8, illustrated therein is a top view of the core sample 132 of Figure 6. Figures 7 and 8 show that the layers 602, 604 of core sample 132 may be separable relative to each other when outside of the core holder 100. It should be noted that those skilled in the art will understand that core sample 132 may comprise more than two layers. For example, one or more additional layer may be sandwiched between the layers 602, 604 shown in Figures 7 and 8.

[0064] In some embodiments, core sample 132 is cylindrical in shape and has a length of about 3 inches to about 12 inches, or about 1 inch to about 3 inches, or about 1.5 inches, and a diameter of about 1.5 inches.
Sleeve

[0065] Referring to Figures 9 and 10, illustrated therein are perspective and end views, respectively, of a sleeve 126 according to an exemplary embodiment.
Sleeve 126 has a body 902 having a first end 904, a second end 906 and a volume 908 therebetween. First opening 910 and second opening 912 provide for body 902 to receive at least one core sample 132 therein. When inserted into core holder 100, sleeve 126 may form a fluid tight seal with the core holder 100. In one embodiment, sleeve 126 can be made out of rubber.

[0066] Typically, core sample 132 is inserted into sleeve 126 through one of openings 910 and 912. Once the core holder 100 has been assembled and sealed, a pressurized fluid may be provided to the core holder 100 through the confining pressure port 134, as shown in Figure 4, such that the pressurized fluid can be passed into the annulus and thereby exert an overburden pressure on the core sample within the sleeve 126, for example.

[0067] Sleeve 126 holds the core sample 132, the distributers 130 and the spacers 128 in place. Sleeve 126 also connects (e.g. slidingly couples to) end caps 124 at first end 904 and second end 906 to stabilize core sample 132 therein.
Sleeve 132 also provides for applying a confinement pressure to the core sample 132 and, after applying the confinement pressure, sleeve 126 seals the core sample 132.
Distributor

[0068] Referring to Figures 11 and 12, illustrated therein are perspective and end views, respectively, of a distributor 130 according to an exemplary embodiment.

[0069] Distributor 130 provides for distribution of the injection fluid (e.g. water or a water-based fluid) throughout the core sample 132 when the core sample 132 is present in sleeve 126, and for collection of the produced fluid from the core sample 132. One distributor 130 is positioned within sleeve 126 at one end of core sample 132 to distribute fluid entering core sample 132 across an area of the core sample 132. One distributor 130 is positioned within sleeve 126 at the other end of core sample 132 to collect fluid produced from core sample 132 across an area of the core sample 132.
Oil Sample Treatment and Preparation of an Interpretation Diagram

[0070] To differentiate between crude oil produced from different layers of core sample 132 of the core holder 100, each crude oil saturated in each layer of the core sample 132 can be distinguished from each other crude oil saturated in each other layer of the core sample 132. In some embodiments, each crude oil saturated in each layer of the core sample 132 can be distinguished from each other crude oil saturated in each other layer of the core sample 132 by the presence or absence of a tracer. For example, each layer of core sample 132 in the core holder 100 can be saturated in a fluorescein (e.g. oleic fluoresceins) and/or dye that can be used as a tracer to distinguish between the crude oil produced from each of the layers of the core sample 132 and present in the product fluid from the core sample 132. Accordingly, the product fluid from the core sample 132 can be referred to as a mixture of the crude oils saturated in the layers of the core sample 132 within the core holder 100.

[0071] It should be noted that although the embodiments and examples herein typically refer to the core holder 100 as holding a core sample 132 comprising three layers, two or more layers may be tested in parallel in core holder 100. It should also be noted that before the layers of the core sample 132 are saturated with a crude oil sample, each crude oil sample has already been dyed or fluorescein has already been added.

[0072] Hereinafter, when referring to the exemplary layers of core sample 132 of core holder 100, the following references will be used to refer to each layer of core sample 132 being absorbed with crude oil saturated with the following tracers (or a lack of a tracer): core sample layer 0-1 will refer to a core sample layer saturated with unmarked crude oil (e.g. no tracer); core sample layer 0-2 will refer to a core sample layer absorbed with crude oil treated with a green oleic dye tracer; core sample layer 0-3 will refer to a core sample layer absorbed with crude oil treated with a red oleic dye tracer; core sample layer 0-4 will refer to a core sample layer absorbed with crude oil treated with a oleic fluorescein type A tracer; core sample layer 0-5 will refer to a core sample layer absorbed with crude oil sample treated with a oleic fluorescein type B
tracer. In the above mentioned oleic fluorescein tracers, nile red (C20H18N1202) or the like can be used as the type A (e.g. red) fluorescein, and C201-11205 or the like can be used as the type B (e.g. yellow-greenish) fluorescein.

[0073] To analyze the fluid produced during the waterflooding test and to determine a volume of crude oil produced from each layer of the core sample 132, the resulting color of the produced crude oil (in the case of dyes being used as tracers) or the amount of fluorescence of the produced crude oil (in the case of fluoresceins being used as tracers), or different combinations of tracer-labeled crude oil mixtures, can be compared to interpretation diagrams (for example, the interpretation diagram shown in Figure 13) created prior to conducting the waterflooding experiments, where the interpretation diagrams are created from known quantities of crude oil in various core samples. The interpretation diagrams (see for example Figure 13) therefore provide , . , correlations between compositions of uniquely labeled crude oil samples and the resulting colors or fluorescence quantity.

[0074] The process for preparing the above mentioned interpretation diagrams can be described as follows: first, mix all labeled oil samples to be saturated into layers of a core sample for the waterflooding experiments in a series of test samples, each test sample in the series of test samples having a different volume composition ratio of the labelled oil samples. For example, each concentration of each oil sample may vary between 0% by volume and 100% by volume uniformly in the series of test samples.
Then, an interpretation diagram can be constructed based on observed colors and/or fluorescence of each of the series of mixtures of with known concentrations.
An example interpretation diagram is provided in Figure 13.

[0075] During an experiment, as oil is produced from core holder 100, the oil is placed on filter paper to read its hue. Based on the hue reading of the mixed oil produced from core holder 100 and the interpretation diagrams generated for each of the tracers/fluoresceins in the core sample 132, the volume percentage of each dye in the produced oil can be determined.

[0076] In one embodiment, the core sample 132 can be three layers of crude oil samples, each oil sample labeled with a tracer to quantify the oil extracted from each layer. One or more analytical instruments (not shown) may be provided for analysis of effluent fluid flowing from core holder 100. Suitable analytical techniques and instruments for use with the core holder 100 are discussed in more detail below. It is envisaged that a sample of effluent fluid flowing from core holder 100 can be directed to the analytical instrument(s). Alternatively, the analytical instrument(s) may comprise at least one probe, sensor, or detector that is located on an effluent line coupled to core holder 100, thereby providing for direct analysis of the effluent fluid flowing through the effluent line. For example, in the case of infrared (IR) analysis, the effluent flow may be irradiated with IR radiation produced by an IR source and an IR detector may be used to detect infrared radiation that is transmitted through the flow (i.e. is not absorbed by the effluent flow). In this case, the analytical instrument may be a Fourier Transform (FT) IR
analytic instrument that generates a transmittance or absorbance spectrum showing the wavelengths at which the effluent fluid absorbs IR radiation. Other analytical methods for identifying oil mixing composition could include but are not limited to color detection methods, flu fluorescein detection, High-Performance Liquid Chromatography (HPLC), etc.
Methods to Saturate Core Samples

[0077] Referring to Figures 14 and 15, illustrated therein are two methods 1400 and 1500, respectively, for saturating core samples for performing waterflooding tests as described herein.

[0078] In method 1400, at step 1402, a core sample (e.g. either natural or artificial core samples such as core sample 132) is inserted into a core holder (e.g. core holder 100) and saturated under reservoir conditions (e.g. conditions similar to those found in Bakken tight formations). For example, the reservoir temperature can be in a range of about 30 C to about 140 C and the initial reservoir pressure can be in a range of about 28000 kPa to about 34500 psi.

[0079] In some embodiments, a formation brine comprising one or more of Na+, K+, Ca2+, Mg2+, Cl-, HCO3-,SO4-,C032" or the like may be used to saturate the core sample 132 prior to saturation with an oil sample to mimic the reservoir conditions of a natural core sample. For instance, in some natural samples the total dissolved solids in reservoir can be approximately 100,000 mg/L.

[0080] In some examples, during the saturation process, the pressure can be in a range of about 300 kPa to about 400 kPa under a fluid injection rate of about 0.05 cc/min.

[0081] For example, the temperature of the core holder during saturation is in a range of about 30 C to about 140 C.

[0082] Saturation of the core samples with the formation brine can aid in mimicking reservoir conditions before oil is extracted using the formation water.

[0083] Before saturation of the core sample, various physical properties of the core sample may be measured. For example, the porosity of the core sample, the permeability of the core sample, etc. can be measured. In some embodiments, the permeability of tight rock can be smaller than 0.5 md and the porosity can be in a range of about 6% to about 16%.

[0084] At step 1404, labelled oil samples (e.g. selected based on different core sample requirements from oil samples 1, 2, 3, 4, 5) will be displaced (e.g.
injected) into the core samples until the connate water saturation is reached. Parameters such as the initial oil saturation and initial water saturation may be recorded.

[0085] At step 1406, after the saturation process, the core sample is removed form the core holder and cut to a size to accommodate a core configuration within the core holder. Various configurations of core samples with the core holder are described below.

[0086] At step 1408, the saturated core sample is sealed into a sleeve (e.g.
sleeve 126) for aging. In some embodiments, the saturated core samples are aged for a period of about 10 days to about 15 days.

[0087] Method 1400 may be repeated for different core samples having varying permeabilities for conducting core flooding tests as described herein.

[0088] Alternatively, in method 1500, at step 1502 a core sample (e.g.
either natural or artificial core samples such as core samples 132) cut to a size to accommodate a core configuration within the core holder. Various configurations of core samples with the core holder are described below.

[0089] At step 1504, the cut core sample is inserted into a sleeve (e.g.
a sleeve having a same shape as the core sample to be saturated) and placed into the core holder.

[0090] At step 1506, the core samples are saturated with a formation brine under reservoir conditions. After saturation of the core sample, various physical properties of the core sample may be measured. For example, the porosity of the core sample, the permeability of the core sample, etc. can be measured. In some embodiments, permeability of tight rock can be smaller than 0.5 md and the porosity can range from 6% to 16%.

=

[0091] Again, for example, the pressure of the core holder during saturation is in a range from about 300 kPa to about 400 kPa under a fluid injection rate of about 0.05 cc/min.

[0092] For example, the temperature of the core holder during saturation is in a range of about 30 C to about 140 C.

[0093] Saturation of the core samples with the formation brine may provide for mimicking an initial reservoir condition, the oil will be flooded the brine saturated core to generate the connate water saturation, as injected oil cannot displaced all the water in the core. The connate water plus the mobile oil in the core is similar to the reservoir condition when we develop the reservoir at the very beginning.

[0094] At step 1508, labeled oil samples (selected based on different core sample requirements from oil samples 1, 2, 3, 4, 5) are displaced into the core samples until the connate water saturation of the core samples is reached.

[0095] During step 1508, parameters of the core samples including but not limited to initial oil saturation and initial water saturation can be measured and recorded.

[0096] At step 1510, the saturated core sample is sealed into a sleeve (e.g.
sleeve 126) for aging. In some embodiments, the saturated core samples are aged for a period of about 10 days to about 15 days.
Core Design

[0097] Once the core samples have been saturated (as described above), waterflooding testing can be conducted on the core samples in parallel in a single core holder using the configurations provided below to evaluate imbibition effects.
For example, as shown in Figures 16 to 19, three core samples having varying permeabilities can be tested simultaneously in a single core holder 100.

[0098] In one embodiment, core flooding tests using core holder 100 can be conducted on three sample cores representing three adjacent layers in a target reservoir. As noted previously, core holder 100 can be used with natural cores (e.g.
cores removed from an oil well) or artificial cores, as previously described.

[0099] Referring to Figures 16 to 19, in one embodiment, three core samples can be tested based on the varying permeabilities of the core samples. For example, in tests measuring the effects of imbibition on three adjacent core samples in an oil well, the three core samples can be labeled as core sample #1 having an ultra-low permeability core, (e.g. a permeability of about 0.1 d), core sample #2 having a low permeability core (e.g. a permeability of about 1 d) and core sample #3 having an ultra-low permeability core (e.g. a permeability of about 0.1 d but lower permeability than core sample #1).

[0100] Hereinafter, when using the references core sample #1, core sample #2 and core sample #3, it should be understood that the permeabilities of the core samples #1, #2 and #3 relative to each other are as follows: permeability of core sample #2 >
permeability of core sample #1 > permeability of core sample #3.

[0101] For all core configurations, it may be necessary to place particle filter paper (not shown) between adjacent core layers in the core holder 100.
Moreover, to mimic natural reservoir conditions, the multi-layer core holder 100 may be placed in an oven to settle to increase the temperature of the core samples prior to testing. A
confining pressure may also be added to the core samples prior to testing to mimic natural reservoir conditions. For examples, the temperature of the core samples within the multi-layer core holder 100 may be increased to be in a range between about 30 C
and 140 C and the pressure of the core samples within the core holder can be increased to be in a range from about 20000kPA to about 35000 kPa, or about kPa to about 32000 kPa, or about 23923 kPa to about 30473 kPa.

[0102] The following paragraphs describe various exemplary and non-limiting configurations of three core samples within a core holder 100. The differences of the exemplary configurations will be hereinafter explained.

[0103] The first exemplary core configuration (see Figure 16): place core #1 on top, core #2 in the middle and core #3 in the bottom of core holder 100. Under this configuration, there are two ways to select oil samples (the first oil sample combination is 0-2 and 0-3; the second oil sample combination is 0-4 and 0-5), and each oil sample combination can have two saturation methods. The first oil sample combination (0-2 and 0-3): core #1 is saturated with 0-3, core #2 is saturated with 0-1 and core # 3 is saturated with 0-2; or core # 1 can be saturated with 0-2, core # 2 can be saturated with 0-1 and core #3 can be saturated with 0-3. The second oil sample combination (0-4 and 0-5): Core #1 is saturated with 0-4, Core #2 is saturated with 0-1 and Core #3 is saturated with 0-5; or Core #1 can be saturated with 0-5, Core #2 can be saturated with 0-1 and Core #3 can be saturated with 0-47. The arrows shown in Figure 16 indicate the flow direction of injected water during waterflooding processes.

[0104] The second exemplary core configuration (see Figure 17): place Core #3 on top, Core #2 in the middle and Core #1 in the bottom. Under this configuration, there are two ways to select oil samples (the first oil sample combination is 0-2 and 0-3; the second oil sample combination is 0-4 and 0-5), and each oil sample combination can have two saturation methods. The first oil sample combination (0-2 and 0-3):
Core #1 is saturated with 0-3, Core #2 is saturated with 0-1 and Core #3 is saturated with 0-2;
or Core #1 can be saturated with 0-2, Core #2 can be saturated with 0-1 and Core #3 can be saturated with 0-3. The second oil sample combination (0-4 and 0-5):
Core #1 is saturated with 0-4, Core #2 is saturated with 0-1 and Core #3 is saturated with 0-5;
or Core #1 can be saturated with 0-5, Core #2 can be saturated with 0-1 and Core #3 can be saturated with 0-4. The arrows shown in Figure 17 indicate the flow direction of injected water during waterflooding processes.

[0105] The third exemplary core configuration (see Figure 18): place Core #2 on top, Core #1 in the middle and Core #3 in the bottom. Under this combining method, oil sample selection will be 0-4 and 0-5. This oil sample combination can have 2 saturation methods: Core #1 is saturated with 0-4, Core #2 is saturated with 0-1 and Core #3 is saturated with 0-5; or Core #1 can be saturated with 0-5, Core #2 can be saturated with 0-1 and Core #3 can be saturated with 0-4, as illustrated in Figure 18.
The arrows shown in Figure 18 indicate the flow direction of injected water during waterflooding processes.

[0106] The fourth exemplary core configuration (see Figure 19): place Core #3 on top, Core #1 in the middle and Core #2 in the bottom. Under this combining method, oil sample selection will be 0-4 and 0-5. This oil sample combination can have two saturation methods: Core #1 is saturated with 0-4, Core #2 is saturated with 0-1 and ., Core #3 is saturated with 0-5; or Core #1 can be saturated with 0-5, Core #2 can be saturated with 0-1 and Core #3 can be saturated with 0-4, as illustrated in Figure 19.
The arrows shown in Figure 19 indicate the flow direction of injected water during waterflooding processes.

[0107] It should be noted that in the four exemplary core configurations provided above, core #2 (having the highest permeability) is saturated with 0-1 (no tracer). To evaluate the oil recovery contribution of imbibition effects, the low permeability core is typically impacted by high capillary pressures and stronger imbibition effects. Therefore, the oil saturated in relatively low permeability cores are shown as traced (e.g. by dye of fluorescein). Tracing the oil samples in the low permeability cores may provide for more accurate measurements when determining the contributions of the oil production in low permeability cores. However, if the oil samples labelled with tracer are saturated into the high permeability core samples, the methods described above will not change.
Evaluation of Production from Different Layers

[0108] By utilizing the first and second core configurations (as referred to above), studies may be performed to analyze the effects of distributions of different permeable layers on the imbibition effects during watering flooding processes in a tight reservoir, and waterflooding effects on production performances. Because different layers may be saturated with different treated oil samples, the colors of produced oil (for 0-2 and 0-3) may change in relation to the volume of oil produced from different layers;
the similar principle can be applied to analyze the layer's contribution during waterflooding processes based on fluorescence quantities in the produced liquid.
The Effect of Gravity

[0109] In the vertical direction, the effect of gravity on the injected water may be determined by analyzing the experimental results using the third and fourth core configurations (as referred to above). For the third core configuration, the gravitational effects provide a positive influence on the imbibition effects; on the other hand, gravitational effects would impose a negative influence on imbibition effects if the fourth core sample configuration is applied.

Interactions between Different Layers

[0110] Because vertical heterogeneous differentiation is possible in tight oil reservoirs, the presence of interactions between different layers may be significant during waterflooding. The third and fourth core configurations may be utilized to mimic the normal/inverted rhythmic deposition in an oil reservoir. For reservoirs formed by different rhythmic deposition processes, imbibition effects would result in interactions between different layers. By measuring colors or fluorescence quantities of produced oil, interactions between different layers resulted from imbibition effects may be determined.
Core Flooding Experimental Procedures

[0111] After choosing the core configurations provided above, the aged core samples may be placed into multi-layer core holders accordingly. Following this, the oven temperature and confining pressure may be set based on actual pressure and temperature conditions within the target formation. Displacing fluids (e.g.
water or a water-based fluid) are then injected into the core sample (e.g. core #2) with higher permeability.
Analysis on Experimental Data Residual oil analysis

[0112] After waterflooding is complete, core samples can be removed from the multi-layer core holder 100. The distribution of residual oil in the core samples can then be analyzed using an analyzer (not shown), as described above (e.g. a CT
scanner).
The influences of water drive and imbibition effects on core samples with different permeability can be determined under different core configurations (as described below) based on the analysis with the analyzer (not shown).

[0113] By combining the experimental residual oil distribution results with actual field productions, predictions may be made on residual oil distributions based on different producing schemes, and thus may provide a theoretical background for the implementation of future producing measures.
Analysis on oil production contributed by imbibition effects in different layers

[0114] As core sample #2 has a higher permeability when compared to core sample #1 and core sample #3, crude oil saturated in these three core samples is produced according to different displacement mechanisms. For example, crude oil produced from core sample #2 may be mainly influenced by water drive effects;
whereas crude oil produced from core samples #1 and #3 may be mainly influenced by imbibition effects.

[0115] The fluid produced during waterflooding processes collected from core holder 100 comprises crude oil from each of the core samples of core holder 100. The produced fluid may be dewatered for analyzing the crude oil from each of the core samples. If the oil samples were treated with dye tracers, the colors of produced oil mixtures can be compared against the pre-determined interpretation diagrams to determine the volumetric composition of each crude oil component (e.g. 0-1, 0-2 and 0-3), and thus to analyze the relationship between volumes of produced oil displacement by water drive and imbibition effects from different layers.

[0116] For experiments involving oil samples treated with fluoresceins, the fluorescence quantities for corresponding wavelength A and wavelength B can be measured and compared against the pre-determined curves. Based on the volumetric composition of oil samples (e.g. 0-1, 0-2 and 0-3) within the produced oil mixture, the contributions of oil production from water drive and imbibition effects can be interpreted.

[0117] For each core configuration, if the imbibition effects are ignored, the flowing equation exists for the relationship between oil productions from layers with different permeability and total oil production:
= x zickiAAi (1) where: Q7: oil production from layer i (core #j);
Q: total oil production from specific core configuration;
ki: Effective permeability of oil sample saturated in layer i (core #j);
Ai: cross section area for layer i (core #j);
A: total cross section area for core #1 to #3.

the number order of core layer in the multi-layer core holder, in which max i equals to max];
j: the number order of core samples, which could be different from i.

[0118] However for actual production processes, due to the presence of imbibition effects, the contribution from each layer can be expressed by:
Qi = Q x (2) where: Qi: oil production from layer i;
Q: total oil production from the core configuration;
Ai: fraction of oil volume produced from layer i against total produced oil volume, interpreted from the above mentioned diagrams/ curves for different colors and fluorescence quantities for different wavelengths.

[0119] The oil produced by imbibition effects for each layer can be expressed below:
QimbQiQi (3) Examples 1. Procedure 1.1 Core preparation

[0120] 1) Saturate a high permeability core (e.g. ¨10 mD) with red dye.

[0121] 2) Cut the core in three pieces. One piece is used for determining relative permeability test. One or two pieces are used for remounting into multi-layer core holder.

[0122] 3) Repeat the step from 1) to 2) for a low permeability core (1 mD). It is worth noting that the low permeability core is saturated with a dye having different color (such as a green dye).

[0123] One representative diagram of an exemplary core configuration is shown in Figure 20. In this configuration, the middle layer (e.g. having a length of 20 cm, a width of 5 cm and a thickness of 1 cm) is used as the high permeability core.
The over-and under- burden layers are the same low permeability cores. The location of the injector and producer are shown in Figure 20. The constant pressure of the well is set to 300 kPa and 100 kPa for the injector and producer respectively.
1.2 Determine relative permeability curves

[0124] Using the unsteady state waterflooding procedure to obtain the production data for determining the relative permeability curves. One exemplary calculation method can be found in Johnson, E. F., Bossler, D. P., & Bossler, V. 0. N. (1959, January 1).
Calculation of Relative Permeability from Displacement Experiments. Society of Petroleum Engineers.
1.3 Conduct Core Flooding Tests on Multi-layer Cores

[0125] After remount the cores with different permeability into the multi-layer core holder, conduct the waterflooding and record the production data. The recording data are production time, produced oil volume, water cut, pressure difference, sample oil color.
1.4 Treatment of Core Flooding Results

[0126] 1) For each time step (30 mins), the produced liquid is centrifuged to separate the oil and water.

[0127] 2) A brand new pipette was used to sample the produced oil at each time step and write the step number on a test paper.

[0128] 3) Take a picture of oil pots in test paper.

[0129] 4) Use a software to identify the mixed color in HSV (Hue, Saturation, Value) version.

[0130] 5) The hue of the mixed oil is used to calculate the color composition (or oil composition) based on the pre-established color plate.

[0131] 6) Based on the determined oil production from different permeability cores, calculate the average oil saturation of different cores by material balance equations.

[0132] 7) Using the Eq. (1) above to calculate the oil production without considering imbibition contribution.

[0133] 8) Using the Eq. (3) to estimate the imbibition contribution of different permeability cores.
Results and discussion 2.1 The role of imbibition in tight formations

[0134] Figure 21 shows the oil recovery over time. Oil recovery of the experiment is much higher than that calculation results before 1000 mins. After 1000 mins, the oil recovery of experiment is slightly lower than that in the calculation. Figure 22 indicates that the imbibition can significantly improve the oil recovery rate. However, for the improvement of final oil recovery, the imbibition does not play an important role.
2.2 Imbibition contributions in different permeability cores

[0135] Based on the treatment mentioned in Section 1.4, above, the oil rate from different permeability cores can be identified as shown in Figure 24.
2.3 Validation of analysis method in the patent

[0136] In Eq. (1), three kinds of unknowns must be known to calculate the oil rate from different permeability cores. The three kinds of unknowns includes total oil rate (Q), effective permeability of oil-phase in different permeability regions (Koi), cross section areas of different permeability regions (Ai). It should be noted that i in Koi and Ai stands for a certain permeability core.

[0137] According to Sections 1.2 and 1.3, the average oil saturations and relative permeability curves of different permeability cores are obtained. The Q and Ai can obtained from production data and core size, respectively. By using Eq. (1), the oil rate without considering imbibition can be calculated. Figure 23 shows the simulation and calculation results of core flooding tests.

[0138] Based on Eq. (3), the oil rate difference between high and low permeability core can be calculated. The results are shown in Figure 24. For high permeability region, the oil rate considering imbibition effects is always higher than that ., without considering imbibition. It indicates that imbibition has a strong positive impacts on high permeability region. For low permeability region, the imbibition effects become more complex. The oil rate considering imbibition is initially higher and then lowers without considering imbibition.

[0139]
While the above description provides examples of one or more apparatuses, methods, or systems, it will be appreciated that other apparatus, methods, or systems may be within the scope of the claims as interpreted by one of skill in the art.

Claims (15)

Claims What is claimed is:

1. A method for determining imbibition effects of waterflooding on crude oil produced from at least two core samples, the method comprising:
providing the at least two core samples to a core holder, each core sample forming a layer within the core holder, and each core sample being absorbed with crude oil that is distinguishable from other crude oil absorbed on the other core samples, and each core sample having a permeability that is different than a permeability of the other core samples;
conducting the waterflooding on the core samples by injecting a first fluid into the core holder to produce a second fluid, the second fluid comprising at least a portion of the crude oil of each of the core samples;
analyzing the second fluid to determine a volume of one portion of the crude oil produced from one of the core samples; and determining, based on the volume of the one portion of the crude oil, a volume of crude oil produced due to imbibition effects from the one of the core samples based on the permeability the one of the core samples.

2. The method of claim 1, wherein the first fluid is injected into the core sample having the highest permeability relative to the other core samples.

3. The method of claim 1 or claim 2, wherein the crude oil of at least one of the core samples is saturated with a tracer to be distinguishable from the other crude oil absorbed on the other core samples.

4. The method according to any one of claims 1 to 3, wherein the providing the at least two core samples is providing three core samples.

5. The method according to any one of claims 1 to 4, wherein a temperature of the core holder is in a range of about 0 °C to about 177 °C.

6. The method according to any one of claims 1 to 5, wherein a pressure of the core holder is in a range of about 0 kPa to about 34473 kPa.

7. The method of claim 3, wherein the tracer is one of a dye and an oleic fluorescein tracer.

8. An apparatus for evaluating imbibition effects of waterflooding on crude oil produced from at least two core samples, the apparatus comprising:
a body, the body having:
a first end;
a second end spaced apart from the first end;
a volume defined by an inner wall of the body, the volume extending between the first end and the second end for housing at least two core samples with a permeability of at least one core sample being different than a permeability of the other core samples where each core sample forms a layer within the body of the apparatus;
an inlet disposed at the first end for receiving a first fluid for conducting the waterflooding; and an outlet disposed at the second end of the body so that the outlet removes a second fluid produced by the waterflooding where the second fluid has at least a portion of the crude oil of each of the core samples.

9. The apparatus of claim 8, wherein the inlet is configured to direct the fluid into the core sample with the highest permeability relative to the other core samples.

10. The apparatus of claim 8 or claim 9, wherein the outlet is configured to receive the fluid from the core sample with the highest permeability relative to the other core samples.

11. The apparatus according to any one of claims 8 to 10, wherein the crude oil of at least one of the core samples is saturated with a tracer to be distinguishable from the other crude oil absorbed on the other core samples.

12. A system for conducting a core flooding test, the system comprising:
an apparatus for determining imbibition effects of waterflooding on crude oil produced from at least two core samples, the apparatus comprising:
a body, the body having:
a first end;
a second end spaced apart from the first end;
a volume defined by an inner wall of the body, the volume extending between the first end and the second end for housing at least two core samples with a permeability of at least one core sample being different than a permeability of the other core samples where each core sample forms a layer within the body of the apparatus;
an inlet disposed at the first end for receiving a first fluid for conducting the waterflooding; and an outlet disposed at the second end of the body so that the outlet removes a second fluid produced by the waterflooding where the second fluid has at least a portion of the crude oil of each of the core samples;
and an analyzer coupled to the apparatus and configured to:
analyze the second fluid to determine a volume of one portion of the crude oil produced from one of the core samples; and determine, based on the volume of the one portion of the crude oil, a volume of crude oil produced due to imbibition effects from the one of the core samples based on the permeability the one of the core samples.

13. The system of claim 12, wherein the inlet is configured to direct the fluid into the core sample with the highest permeability relative to the other core samples.

14. The system of claim 12 or claim 13, wherein the outlet is configured to receive the fluid from the core sample with the highest permeability relative to the other core samples.

15.
The system according to any one of claims 12 to 14, wherein the crude oil of at least one of the core samples is saturated with a tracer to be distinguishable from the other crude oil absorbed on the other core samples.