FIELD

The present disclosure generally relates to testing approaches that may be used in relation to oil reservoirs, and in particular to wettability testing of an oil reservoir.

BACKGROUND

On average, conventional oil production methods will only produce about 30% of the initial oil in place from a petroleum reservoir. The remaining oil (e.g., liquid hydrocarbons), nearly 70% of the initial petroleum resource, is a large and attractive target for oil recovery methods. Initial production (primary) refers to the spontaneous production that utilize natural reservoir energy. Secondary oil recovery refers to oil production from injection of water (waterflooding) which utilize reservoir repressurizing schemes with injected water to increase reservoir pressure and displace more oil. Tertiary oil recovery, or other enhanced oil recovery refers to the process of producing liquid hydrocarbons by methods other than the conventional use of reservoir energy or water floods.

In the field of oil recovery there remains a significant need for producing efficient and cost-effective methods to change wettability to increase recovery, and methods for applying said compositions to subterranean rock formations, wherein the composition is specifically designed for to alter the wettability of the reservoir for the purpose of maximizing recovery.

SUMMARY

One factor related to the ability to recover more oil from an oil reservoir is the wettability of the reservoir. Wettability can impact recovery at any stage of production. Wettability describes the preference of a solid surface to be in contact with one fluid rather than another fluid. This preference is based on atomic-scale surface and interfacial forces (e.g., van der Waals, electrostatic, and steric forces). Since it is not possible to independently measure these three forces, wettability is usually measured by the macroscopic scale expression of the forces. An example would be how high the liquid in a glass tube is drawn above the liquid in the glass. This macroscale observation is the wetting of the glass tube by water as the water displaces air.

Wettability in the context of an oil reservoir refers to the adhesion of crude oil to the rock surfaces. The wettability of the oil reservoir of interest can affect the efficiency of waterflooding operations. The surfaces in the petroleum reservoir are dominantly mineral grains with some associated organic matter. The fluids are water, which is usually saline brine, and crude oil (a mixture of numerous non-aqueous liquid and gaseous hydrocarbons). If oil adheres to the mineral surfaces, we identify the system as oil-wet. In contrast, if the oil does not adhere to the mineral surfaces, the system is considered water-wet. Most petroleum reservoirs have a combination of oil-wet and water-wet surfaces based on localized reservoir conditions. In turn, while the wettability of a system may affect oil recovery methods, it may be difficult to accurately measure or predict the in-situ wettability of the system.

It is presently recognized that the physical characteristics and oil and water chemistry of an oil reservoir of interest play an important role in the wettability of the oil reservoir. Understanding these characteristics and chemistry may allow for more accurate measurement of the reservoir wettability. Additionally, with the ability to accurately measure the reservoir wettability, it may be easier to evaluate modifications to the wettability in such systems. Specifically, oil production may be enhanced by modifying the wettability of an injected water for use in oil recovery. It is presently recognized that replication of in-situ reservoir conditions (e.g., including pH) may allow for more accurate measurement of wettability in a system designed to model oil reservoir behavior (e.g., for evaluation of an oil reservoir's potential for oil recovery and/or for design of improved oil recovery operations). Specifically, the present disclosure recognizes the effect of pH on the wettability of an oil reservoir. Accordingly, wettability testing is described herein that may accurately reflect pH conditions of an oil reservoir of interest. In turn, more accurate wettability measurements maybe provided, which may assist in evaluating techniques designed to modify the wettability for oil recovery from the reservoir. The term “oil” is used throughout this disclosure. It should be understood that “oil” may encompass any non-aqueous phase liquid (NAPL). As such, where the term oil may be interchanged with NAPL throughout this disclosure. Furthermore, it should be appreciated that in some contexts “oil” may include liquid and/or gas components. In other contexts, “oil” may refer to a degassed oil. The “oil” may comprise crude oil. “Oil” may also refer to an extract or component of crude oil including, for example, a liquid extract of crude oil. The “oil” may contain hydrocarbon and non-hydrocarbon components.

Accordingly, the following description includes an explanation of the importance of controlling certain variables in a wettability test and presents an improved testing procedure. In addition, as the conditions corresponding to the oil reservoir may be controlled, the response to various changes (e.g., to the aqueous phase or brine of the reservoir) may be more accurately predicted. This may assist in designing injected water to favorably modify the wettability of the oil reservoir for oil production. The modified injected water used in oil recovery may be used in primary recovery, secondary recovery, tertiary recovery, or any other oil production phase or process including any enhanced oil recovery techniques. Furthermore, the improved testing procedure may be extended to assist in development of equilibrium constants that may be used in relation to geochemical models of reservoir wettability.

In relation to wettability of an oil reservoir of interest, a number of important factors relate to the effectiveness of oil recovery from a reservoir. The macroscopic effect is that some of the crude oil or non-aqueous phase liquid (NAPL) “wets” the rock and does not move during normal production practices. This adhesion of oil to rock helps limit recovery in most reservoirs to an average of 30-35% of the initial oil-in-place. In the oil reservoir, some of the oil will directly contact the mineral surfaces and adhere, creating hydrophobic zones where oil can adhere, thus impeding oil recovery in the reservoir.

But much of the oil wetting takes place between oil and mineral surfaces separated by a water film. The mineral surfaces have an electrostatic charge, as do the polar portions of crude oil (the organic acids and bases in the oil). These electrostatic forces may be attractive or repulsive, thus promoting or discouraging oil adhering to the rock.

The organic acids and bases in crude oil are organic frameworks (carbon and hydrogen) with polar groups containing oxygen, nitrogen and sulfur. The carbon and hydrogen portions of the molecule will remain in the bulk oil phase while the polar portions will tend to migrate to the oil-water interface. The polar portions of oil are only a few percent of the total oil, but the polar portions serve as anchors to the mineral surface sites allowing the non-polar portions of the oil to wet (e.g., adhere to) the rock due to the attractive forces acting between the mineral surface and the polar portions of the oil acting through the water film. It has been found that this type of wetting is reversible or transient depending on the electrostatic forces. Specifically, if the surface charges on oil and/or mineral surfaces are altered, the wettability of the system may be changed such that the oil that adheres to the mineral surface may be released allowing for recovery of additional oil from the reservoir.

However, it is also recognized herein that the in-situ reservoir pH may affect the wettability in view of the foregoing understanding regarding the interaction between the polar portion of the oil and the charged mineral surfaces in the reservoir. The term reservoir pH may refer to the in-situ pH of the reservoir brine or the pH of the reservoir generally including all phases present therein. As such, the term in-situ reservoir pH and reservoir pH may be used interchangeable throughout this disclosure to refer to the pH of the oil reservoir of interest.

In view of the foregoing, it is presently recognized that the wettability of oil reservoirs is dependent, at least in part, on the polarity of mineral and oil surface charges, which are in turn dependent on reservoir pH. This means the wettability of oil in petroleum reservoirs can be directly related to reservoir pH through a set of chemical reactions between reservoir surfaces and the polar portions of the oil. In turn, it is recognized that it is advantageous to control a wettability test to reflect reservoir pH to achieve more accurate results. Accordingly, the following disclosure presents wettability testing procedures in which the experimental pH of the test vessel is controlled to replicate reservoir pH to provide more accurate wettability results for characterization of the oil reservoir and evaluation of techniques designed to modify the wettability of the oil reservoir. While the present disclosure primarily discusses a modified flotation test, it may be appreciated that the influence of pH on the wettability test may be generally extrapolated to any test designed to determine the wettability of an oil reservoir. A first aspect of the disclosure includes a method for performing a modified flotation test of a system corresponding to an oil reservoir of interest. The method includes adding a number of samples to a test vessel. The samples include a solid phase sample, an aqueous phase sample, a gas phase sample, and an oil sample. The solid phase sample includes reservoir rock or geologically analogous rock corresponding to the oil reservoir of interest. The aqueous phase sample corresponds to reservoir formation water found in the oil reservoir of interest. The gas phase sample corresponds to a gas phase of the oil reservoir of interest. The oil sample may include a crude oil sample or degassed crude oil sample. In any regard, the oil sample corresponds to an oil of the oil reservoir of interest. In turn, the method also includes controlling a chemistry of the gas/liquid phase sample to achieve an experimental pH value in the test vessel corresponding to conditions of the oil reservoir of interest and allowing contents of the test vessel, after the adding step, to reside for at least a first residence time period while maintaining the experimental pH value in the test vessel corresponding to the oil reservoir of interest based on control of the chemistry of the gas/liquid phase in the test vessel. Thereafter, the method includes separating a first subset of solid phase sample particles in the aqueous phase sample from a second subset of solid phase sample particles in the oil sample from the test vessel after the first residence time period and measuring the relative amounts of the first subset of solid phase sample particles relative to the second subset of solid phase sample particles to determine a measure of the wettability of the system.

A number of feature refinements and additional features are applicable to the first aspect. These feature refinements and additional features may be used individually or in any combination. As such, each of the following features that will be discussed may be, but are not required to be, used with any other feature or combination of features of the first aspect.

For instance, the solid phase sample, the aqueous phase sample, the oil sample, and the gas phase sample may be provided in the test vessel at a volumetric ratio approximating a relative ratio of the reservoir rock, reservoir formation water, the gas phase, and the oil in the reservoir of interest. In an example, the solid phase sample, the aqueous phase sample, the oil sample, and the gas phase sample may be provided in the test vessel at a volumetric ratio of about 1:10:3:20.

In relation to the solid phase sample, the method may also include sizing the reservoir rock particles corresponding to the oil reservoir of interest to allow surface forces to dominate the wettability of the system. For instance, the method may include grinding the reservoir rock corresponding to the oil reservoir of interest into a fine powder. In an example, the reservoir rock corresponding to the oil reservoir of interest may be a sample obtained directly from the oil reservoir of interest. The reservoir rock corresponding to the oil reservoir of interest may include at least one of a sandstone, limestone, dolomite, chalk, chert, carbonate, another oil bearing geological media, or a combination thereof. In one specific context, the reservoir rock corresponding to the oil reservoir of interest may be a shale containing oil.

In an example, the aqueous phase sample may be a produced water obtained directly from the oil reservoir of interest. Alternatively, the aqueous phase sample may include a synthesized water (e.g., a synthetic water with the same or similar water chemistry as the produced water). The synthesized water may comprise a first water (e.g., produced water obtained directly from the reservoir of interest or a synthetic water with the same or similar water chemistry) mixed with a second water. The synthesized water may differ with respect to the produced water in at least one chemical characteristic. For example, the synthesized water may differ with respect to the produced water at least with respect to an amount of total dissolved solids (TDS). In various examples, the amount of TDS of the synthesized water may be greater than or less than the amount of TDS in the produced water. As will be described in greater detail below, this may assist in the evaluation of synthesized water that may be injected into the oil reservoir to modify the wettability for improvement to an oil recovery operation.

In an example, the oil sample may be the oil obtained directly from the oil reservoir of interest. In this regard, the oil sample may comprise crude oil. In one context, the oil sample may be an extract of crude oil. In an example, the extract of crude oil may be a liquid extract of crude oil. Alternatively, the oil sample may be a synthesized oil sample having at least one property in common with the oil of the oil reservoir of interest.

In an example, the gas phase may be atmospheric gas comprising nitrogen, oxygen, argon, and carbon dioxide. Furthermore, controlling the chemistry of the gas phase may include control of at least one of a composition, a temperature, or a pressure of the gas phase. For instance, controlling the chemistry of the gas phase may include maintaining a vessel partial pressure of carbon dioxide in the test vessel at a level corresponding to a reservoir partial pressure of carbon dioxide in the reservoir of interest. As is described in greater detail below, this partial pressure of carbon dioxide may influence the resulting experimental pH in the test vessel, thus allowing the experimental pH to be maintained at or near in-situ reservoir pH. The gas phase may be maintained at a pressure of not less than about 10 psi and not greater than a maximum pressure in the reservoir of interest. In one particular context, the gas phase may be maintained at a pressure of not less than about 10 psi and not greater than a maximum hydrostatic pressure gradient of the system. In either of the foregoing instances, the lower bound of the range may alternatively comprise atmospheric pressure.

In an example, the method may include performing a series of tests on a plurality of test vessels to determine a manner in which the wettability of the oil reservoir of interest changes with a changed parameter. This may include determining an equilibrium constant that describes one or more reactions of the oil reservoir as described by a geochemical model. Accordingly, the method may include preparing a plurality of test vessels, where each of the plurality of test vessels may include a unique respective aqueous phase sample (e.g., a chemically unique sample). For instance, the unique respective aqueous phase samples may each be chemically unique such that at least one chemical property differs for different ones of the respective aqueous phase samples. Each corresponding one of the unique respective aqueous phase samples may, for example, differ with respect to at least one of an amount of total dissolved solids (TDS). In turn, the method may include measuring the relative amounts of the first subset of solid phase sample particles relative to the second subset of solid phase sample particles for each of the plurality of test vessels. Based on the results of the measuring, the method may also include determining an equilibrium constant regarding the wettability of a system comprising the reservoir rock, the reservoir formation water, and the oil of the reservoir of interest based on the relative amounts of the first subset of solid phase sample particles relative to the second subset of solid phase sample particles for each of the plurality of test vessels. For instance, the results of the measuring may be used to fit a curve to the data to determine the equilibrium constant. The equilibrium constant may relate to a computational model regarding the reservoir of interest, and the method may also include using the equilibrium constant in the computational model for determining at least one property of an injected water for injection into the reservoir of interest to interact with a subterranean hydrocarbon reservoir of the reservoir of interest in a primary recovery operation, secondary recovery operation, tertiary recovery operation, or any other enhanced production operation. For instance, it is recognized that a balanced oil-wet/water-wet system (e.g., where the oil reservoir is as equally oil-wet as it is water-wet) may optimize oil recovery. As such, the injected water may achieve a balanced oil-wet/water-wet oil reservoir as a result of the injection of the injected water (e.g., according to a designed water chemistry as described herein) injected into the oil reservoir. The at least one property may include an amount of total dissolved solids (TDS). The determining the at least one property of the injected water may include determining an alteration to a produced water of the reservoir of interest to obtain the injected water. This alteration may include mixing the produced water with a second water.

Moreover, the various test vessels prepared to generate the equilibrium constant may be specifically designed to be acidic or basic in nature. In this regard, reactions in the test vessel due to reactions involving acids or reactions involving bases may be isolated in respective ones of the plurality of test vessels by controlling the pH of the test vessels. Accordingly, an acid equilibrium constant and a base equilibrium constant may be determined based on respective ones of the basic test vessels and the acidic test vessels (e.g., from data collected in relation to a wettability test of the respective ones of the basic test vessels and/or the acidic test vessels). As such, in one particular context, the equilibrium constant may be an acid equilibrium constant derived by a plurality of basic test vessels having a pH greater than 7, greater than 8, or even greater than 9. Alternatively, the equilibrium constant may be a base equilibrium constant derived by a plurality of acidic test vessels having a pH less than 5, less than 4, or even less than 3. Moreover, the equilibrium constant may be an acid equilibrium constant derived by a plurality of basic test vessels having a pH greater than 7, greater than 8, or 9 or greater and a base equilibrium constant derived by a plurality of acidic test vessels having a pH less than 5, less than 4, or 3 or less. Additionally or alternatively, the method may include preparing and measuring a plurality of test vessels as described above and determining, based on the relative amounts of the first subset of solid phase sample particles relative to the second subset of solid phase sample particles for each of the plurality of test vessels, a given one of the unique respective aqueous phase samples that provides a nearest approximation of the first subset of solid phase sample particles and the second subset of solid phase sample particles being equal in relative amounts. This may include determining at least one property of an injected water for injection into the reservoir of interest to interact with a subterranean hydrocarbon reservoir of the reservoir of interest in a production operation (e.g., during primary, secondary, and/or tertiary recovery) based on the given one of the unique respective aqueous phase samples (e.g., to achieve a balanced oil-wet/water-wet system). In an example, the contents of the test vessel may come to an equilibrium during the first residence time period. Additionally, the method may further include expressing the wettability of the system as determined in the measuring step as a wettability value in relation to a wettability index, such as, for example, an Amott index with values that range from −1 to +1.

A second aspect of the present disclosure includes a method for performing a modified flotation test for an oil reservoir of interest. The method includes preparing a plurality of test vessels by adding to each of the plurality of test vessels a solid phase sample comprising reservoir rock corresponding to the oil reservoir of interest, a gas phase sample that corresponds to a gas phase of the oil reservoir of interest, and an oil sample. In turn, the method includes adding to each one of the plurality of test vessels a corresponding aqueous phase sample. Each corresponding aqueous phase samples differs with respect to a value for total dissolved solids (TDS). The method further includes maintaining each of the plurality of test vessels at a condition to produce within each test vessel an experimental pH value corresponding to the pH of the oil reservoir of interest and allowing each of the plurality of test vessels to reside for a residence time period within the test vessel while maintaining the experimental pH value of the oil reservoir of interest based on control of a chemistry of the gas phase sample. In turn, the method includes separating from each of the plurality of test vessels after the residence time period a first subset of solid phase sample particles in the aqueous phase sample from a second subset of solid phase sample particles in the oil sample and measuring the relative amounts of the first subset of solid phase sample particles relative to the second subset of solid phase sample particles for each of the plurality of test vessels. Thereafter, the method includes calculating at least one equilibrium constant regarding the wettability of a system comprising the reservoir rock, the reservoir formation water, and the oil of the reservoir of interest based on the relative amounts of the first subset of solid phase sample particles relative to the second subset of solid phase sample particles for each of the plurality of test vessels.

A number of feature refinements and additional features are applicable to the second aspect. These feature refinements and additional features may be used individually or in any combination. As such, each of the foregoing features that were discussed in relation to the first aspect may be, but are not required to be, used with any other feature or combination of features of the second aspect.

A third aspect of the present disclosure includes a method for increasing oil recovery from a subterranean hydrocarbon reservoir formation. The method includes injecting an injection water into the subterranean hydrocarbon reservoir formation at an injection well, where the injection water interacts with the subterranean hydrocarbon reservoir formation, and where the injection water comprises a recovery index value. The recovery index value corresponds to a wettability of the hydrocarbon reservoir formation in the presence of the injection water as determined by a modified flotation test according to any of the foregoing first or second aspects.

A number of feature refinements and additional features are applicable to the third aspect. These feature refinements and additional features may be used individually or in any combination. As such, each of the following features that will be discussed may be, but are not required to be, used with any other feature or combination of features of the third aspect. For instance, any of the feature refinements or additional features described above in relation to the first aspect may be used in any combination with respect to the third aspect.

Additionally, in an example the method may also include recovering the injection water and a hydrocarbon from the subterranean hydrocarbon reservoir at a production well. The method may also include mixing produced water with a second water to generate the injection water. The recovery index value may be an indication that the injected water interacts with the subterranean hydrocarbon reservoir formation to result in the subterranean hydrocarbon reservoir formation being equally water wet and oil wet.

