Patent Description:
Two-phase relative permeability describes how easily one fluid can be moved through a porous medium in the presence of another fluid. It is an important characteristic of hydrocarbon reservoir rocks and a crucial input to oil and gas reservoir modeling and simulation activities.

The term "wettability" is used as measure a fluid's tendency to stick to (or wet) surfaces compared to a second fluid in the same pore space that is the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids. In the petroleum context, wettability is the tendency of a reservoir rock surface to preferentially contact a particular fluid in a multiphase or two-phase fluid system.

Relative permeability, and multi-phase flow through porous media in general, is dependent on various characteristics of the fluid-fluid-rock system, including rock surface properties, physical properties of each fluid, and flow conditions. One flow characteristic is the non-dimensional "Capillary number" (Ca) that represents the ratio of viscous forces to capillary forces. "Capillary number" (Ca) is usually defined as the superficial fluid velocity times the viscosity of a reference fluid divided by the fluid-fluid interfacial tension. Another characteristic is "wettability", which represents a preference of a rock surface for one fluid over another one, and is manifested as a measurable property known as contact angle. Wettability is often classified as water-wet (average contact angle <NUM>-<NUM> degrees), neutral-wet (~<NUM> degrees), oil-wet (<NUM>-<NUM> degrees), or some variation thereof such as strongly water-wet or weakly oil-wet.

Wettability has a strong influence on multi-phase flow behavior in porous material, such as oil and water, oil and gas, or water and gas flowing through reservoir rock. Reservoir rocks (unlike man-made materials) tend to have spatially varying wettability, i.e., the contact angle varies from location to location on the surfaces within the pore space of a rock. The contact angle distribution is a result of the mineral composition and the geological history of a hydrocarbon-bearing rock as well as surface texture, chemical composition of fluids (e.g., water, oil) in contact with the rock, etc. Prior to contact with oil, rocks are almost always naturally water-wet; as oil invades the pore-space over geologic time, the initial water-wet character may be altered in certain locations due to adhesion of substances within the oil phase. Mechanisms of wettability alteration depend on various local system properties such as pressure, temperature, mineral type, and fluid composition.

When rock samples are extracted from oil/gas reservoirs during the drilling process, they are often contaminated with mud and other fluids and chemicals. When those rock samples are subjected to laboratory experiments to obtain two-phase relative permeability curves or capillary pressure curves, a common lab test procedure is to first clean the rock and then attempt to restore the rock's natural (pre-extraction) wettability. This process of attempting to reestablish a fluid phase distribution and wettability distribution (e.g., contact angles) representative of the subsurface reservoir conditions is referred to as "aging. " A typical aging procedure would involve cleaning the rock sample of contaminants and treating the rock sample with chemicals that induce a water-wet condition. The sample is next saturated with brine, and in a procedure referred to as "drainage", oil is pushed in (hence brine is pushed out) using estimated reservoir conditions of temperature and pressure. This system is then "aged" for a period of time, e.g. <NUM> weeks, allowing wettability alteration to occur, presumably in a fashion similar enough to what had occurred in the real subsurface rock formation so that a realistic wetting condition is restored. <CIT> discloses a method for determining equilibrium wettability of an interface between a void space and a solid phase (mineral matrix, mineral skeleton) of a rock sample in the condition in which the rock is in the stratum after formation of an oil-and-gas field, but before the rock was subjected to man-induced impacts.

In one aspect, a computer implemented method for determining a wettability alteration of a physical rock sample in the presence of at least two fluids according to claim <NUM> is disclosed.

Other aspects include a computer program product tangibly stored on non-transitory computer readable media according to claim <NUM> and a computer system according to claim <NUM>.

One or more of the above aspects may provide one or more of the following advantages. Wettability has a strong influence on multi-phase flow behavior in porous material, such as oil and water, oil and gas, or water and gas flowing through reservoir rock, reservoir rocks can be extracted from oil/gas reservoirs during the drilling process cleaned to measure physical, chemical and geometric properties that are modeled. The modeled rock samples undergo simulated aging and wettability alterations rather than subjecting the samples to the conventional laboratory procedures to obtain two-phase relative permeability curves or capillary pressure curves. The disclosed process of computational "aging" and "wettability alterations" can be performed in a much shorter period of time in comparison to the "aging" times in, e.g. <NUM> weeks, for the physical laboratory approaches mentioned above.

Other features and advantages of the invention will become apparent from the following description, and from the claims.

Referring to <FIG>, a system <NUM> for simulating to numerically simulate the wettability restoration or "aging" process representative of the subsurface reservoir conditions, i.e., "numerical aging" is shown. The system <NUM> in this implementation is based on a client-server or cloud based architecture and includes a server system <NUM> implemented as a massively parallel computing system <NUM> (stand alone or cloud-based) and a client system <NUM>. The server system <NUM> includes memory <NUM>, a bus system <NUM>, interfaces <NUM> (e.g., user interfaces/network interfaces/display or monitor interfaces, etc.) and a processing device <NUM>. In memory <NUM> are a numerical aging engine <NUM> that operates on a digital representation of a physical rock sample that digitally represents a pore space and grain space of the digital representation of the physical material, e. , a physical rock sample (digital rock sample). Also in memory is a simulation engine <NUM> that simulates wettability alteration.

In some embodiments, simulating multi-phase flow behavior occurs through a reservoir rock adjacent a gas or oil well (e.g., drilling rig <NUM>). Determining the multi-phase flow behavior comprises determining the wettability alteration of the physical rock sample.

The digital representation of the physical rock sample can be a third party application that is executed on a different system than server <NUM>. The system <NUM> merely requires the digital representation of a physical rock sample <NUM>' to have the numerical aging engine digitally prepare the digital representation of a physical rock sample. One approach to providing the digital representation <NUM>' of the rock sample is to obtain the representation <NUM>', for example, from a 3D image generated from a micro CT scan of the rock sample.

The memory <NUM> also stores parameters used by the engine <NUM>, such as grain surface properties obtained by assigning mineral types 33a to the grains to determine the surface properties for each of those mineral types, and surface texture and roughness properties. The memory <NUM> also stores parameters such as fluid properties 33b, e.g., fluid density and viscosity of each expected fluid, (e.g., two or more of water, gas, oil) and fluid-fluid interfacial tension properties. The memory <NUM> also stores parameters such as chemical composition data 33c of the fluids and affinity data 33d of the fluid components for the particular mineral types. The memory <NUM> also stores disjoining pressure 33e for each mineral type in combination with the fluids, and a selected 33f aging time used by the aging engine <NUM>. In addition, reservoir pressure and temperature data are also stored. The mineral types evaluated can be those found or expected at the actual site of the reservoir.

The simulation engine <NUM> includes a module 34a to set up the rock sample simulation environment, a module 34b to perform a drainage simulation, and a module 34c to calculate local curvature of surfaces in the pore space. The system <NUM> accesses a data repository <NUM> that stores 2D and/or 3D meshes, coordinate systems, and libraries that can be used for drainage simulations using any well-known computational technique such as computational fluid dynamics or the so called Lattice Boltzmann method.

Referring now to <FIG>, a process <NUM> for numerical aging retrieves <NUM> the digital representation of the pore space and grain space of a rock sample sets up input parameters and conditions, e.g., initial, and boundary conditions, determines <NUM> grain surface properties by assigning mineral types to the grains and determining surface properties for mineral type, determines <NUM> fluid density and viscosity of each fluid, and fluid-fluid interfacial tension determines <NUM> disjoining pressure for each mineral type in combination with the fluids and ages the digital representation of the rock for a time interval by performing a wettability alteration <NUM> (<FIG>). Subsequent to an iteration of the wettability alteration process <NUM>, the process <NUM> determines an amount of change <NUM> of the, e.g., local curvature, contact angle, etc., from a prior iteration of the wettability alteration process <NUM>, and compares the amount to a threshold change amount. Grain surface properties include surface texture, more commonly referred to as surface "roughness" properties that will have an effect on contact angle.

If the change is significant the process <NUM> repeats 49a using a subsequent drainage simulation under specified conditions (<FIG>). If the change is insignificant the process <NUM> can exit 49b or set up <NUM> a subsequent iteration of the rock sample simulation environment assigning a subsequent set of input parameters. The subsequent iteration <NUM> of the rock sample simulation can be used to change any of the elements of <FIG>, as illustrated by the bracket <NUM>.

The term "wettability" is used as measure a fluid's tendency to stick to (or wet) surfaces compared to a second fluid. That is "wettability" is the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids. In the petroleum context, wettability is the tendency of a reservoir rock surface to preferentially contact a particular fluid in a multiphase or two-phase fluid system. Wettability can be influenced by an amount penetration of one fluid through another fluid, so as to cause a film breakage (i.e., the breakdown of the ability of a film of the first fluid to protect a surface from the second fluid. The wettability alteration process discussed below is used to simulate the effect that one fluid has on another fluid over time increments and surface and/or pore surface increments.

Referring now to <FIG>, a process <NUM> for simulating wettability alteration is shown. In this example, the process <NUM> sets up the rock sample simulation environment and assigns input parameters as specified above. The rock sample simulation environment includes the digital representation <NUM>' of the pore space and grain space of the rock sample represented in the memory as a set of nodes <NUM>" that have associated therewith the assigned input parameters as needed for wettability simulation.

For example, the 3D image generated from a micro CT scan of the rock sample can be digitized and represented, e.g., as a graph structure in memory with the graph having nodes and leafs, e.g., on a pixel by pixel basis (or groups of pixels). Pores can be identified by relative contrast levels. The process may execute a best-path algorithm (for example, using the Dijkstra method) to find pore lengths. The best path may be considered the centerline for the pore. The process identifies a contrast level for each node / pixel on the centerlines and can filter high-frequency values of contrast level, the process may use other filtering and/or spatial smoothing techniques to filter high frequency values. The nodes can be annotated with input parameters needed for wettability simulation.

Other representation can be of voxels. For example, prior to the simulation, the rock simulation environment is modeled as a collection of voxels. A triangulated mesh image process (a type of polygon mesh used in computer graphics, which comprises a set of triangles connected by common edges or corners) and segmentation mesh construction can be used to represent the surface of the rock sample in the simulation environment, and fluid is represented by voxels that are allowed to be 'cut. ' The voxels are cut to conform the voxels to the mesh. Each voxel cell is assigned attributes.

The process <NUM> performs a drainage simulation <NUM> to establish a fluid phase distribution for user-specified conditions (that can be representative of either laboratory and/or reservoir conditions), such conditions including pressure and temperature of the reservoir. The drainage simulation is iteratively perform on portions of the rock sample. Most often, the rock sample is initially uniformly water-wet, but other initial wettability definitions are possible. The process can access, e.g., 3D meshes and coordinate systems, which together with libraries are used to simulate drainage using any well-known computational technique such as computational fluid dynamics or the so called Lattice Boltzmann method. The simulation will establish fluid phase distribution for user-specified conditions through the rock sample representation <NUM>'.

The process <NUM> performs a local curvature calculation <NUM> at every surface in the rock sample representation <NUM>', e.g., exterior surfaces and interior pore surfaces. From the local curvature calculations, the process <NUM> calculates <NUM> local capillary pressure at each surface location and determines <NUM> whether water-film breakage may occur at the surface, by comparing local capillary pressure to the sum of geometric induced, curvature-based pressure and disjoining pressure. For very small pores, the disjoining pressure effect due to a very large curvature will outweigh the effect of a material based disjoining pressure. In that case, only the curvature of the pore space is of significance. This scenario may happen in clay or in shale type formations.

The curvature of the surface of the rock is calculated using differential geometry. One particular tool is "VTK" (Visualization Toolkit an open-source, freely available software system for 3D computer graphics. ) Other tools, etc. could be used as well as other techniques could be used. Differential geometry is also discussed in <NPL>). The process <NUM> calculates <NUM> a spatial distribution of wettability by taking a subset of surface locations eligible for water-film breakage and locations in contact with the non-wetting phase which is obtained after drainage simulation and determines <NUM>, a degree of wettability alteration based on the chemical composition of the local fluid and the aging time, with longer aging times likely resulting in more oil-wet (larger) contact angles compared to shorter aging times. The process can then classify the wettability as water-wet (average contact angle <NUM>-<NUM> degrees), neutral-wet (~<NUM> degrees), oil-wet (<NUM>-<NUM> degrees).

The wettability alteration simulation can be a slow, dynamic process that occurs over small discrete time intervals. At any time during a displacement simulation, each surface element is tested to determine whether an alteration to, e.g., the contact angle occurred and determine the amount of the alteration. The history of the spatial expansion of the wettability alteration thus is captured as well. At any time increment, during the displacement simulation, the process measures the applied local pressure and compares that with the sum of the curvature based local pressure and the disjoining pressure. If film breakage occurs, the process modifies the local wettability classification. At any time increment, during the displacement simulation, the process measures the time that a second fluid, e.g., oil has been in contact with a surface element, and modifies the wettability classification correspondingly. The process continues with displacement simulation, e.g. relative permeability, by injection of a fluid or a capillary pressure increase of pressure during drainage. The process is performed where a final pressure represents reservoir pressure as described above or can be subdivided into several drainage pressure iterations where wettability alteration is carried out after each step followed by pressure ramp-up. The process <NUM> can thereafter allow the fluid phases to redistribute due to the modified surface wettability and repeat the process <NUM> until there is no or an insignificant (empirically or predetermined) amount of change in wettability.

With the process <NUM>, the process provides <NUM> a numerical prediction of surface wettability alteration and resulting spatial distribution of wettability in the form of the calculated contact angle at each surface location. In process <NUM> a discrete surface element and one or more fluid elements are in communication, enabling local wettability determinations to depend on the local properties of mineral type, fluid properties, fluid composition (e.g. presence of asphaltenes), capillary pressure, and disjoining pressure. The slow dynamic wettability alteration allows non-wetting fluid to intrude into very small pores, because the wettability can be changed in such a way that capillary pressure does not need to be overcome.

In extensions, it is possible to use the method iteratively where wettability alteration is performed followed by fluid phase redistribution, with the process <NUM> being repeated until the system <NUM> converges (as measured by further repetitions not significantly changing the results (e.g., contact angles). Thus the process <NUM> could reference an established threshold value that provides an amount by which a contact angle would need to vary to otherwise halt further iterations of wettability alternation simulations.

The process <NUM> could also be used within a relative permeability simulation to predict, for example, wettability alteration that occurs during a physical relative permeability lab experiment (these can take months so some further alteration of wettability is possible even if a wettability restoration protocol was performed).

Achieving a force balance is the basic mechanism that defines a qualification rule for a wettability alteration. The qualification rule for a wettability alteration involves three forces:.

As explain in (<NUM>) above, the force balance requirement for film rupture can be expressed as: <MAT> or the capillary pressure is greater than the curvature based pressure plus the disjoining pressure
or <MAT> or the capillary pressure minus the curvature based pressure is greater than the disjoining pressure.

Referring to <FIG>, a verification process <NUM> is shown. The verification process provides a verification of the wettability calculation of <FIG>, by use <NUM> of a measure of the wettability of a rock sample in the form of a wettability index, such as Amott index and USBM method (United States Bureau of Mines) index that are experimentally determined We. These values are used to verify and/or calibrate the predicted wettability distribution resulting from the numerical aging process <NUM> of <FIG>. The Amott test is a well-known empirical wettability measurement for reservoir cores in petroleum engineering that combines two spontaneous imbibition measurements and two forced displacement measurements and defines two different indices, the Amott water index and the Amott oil index obtained from core analysis experiments.

The wettability index simulation process <NUM> performs <NUM> a numerical aging simulation based on estimated input parameters (see above) to provide simulation results. The process uses the simulation results to determine <NUM> predicted values of the wettability index Wp. The wettability index simulation process <NUM> compares <NUM> the predicted values to experimentally measured values We (from <NUM>) and when the values do not match <NUM>, Wp ≠ We ± T sufficiently within a user defined tolerance T. The user defined tolerance on the match can be empirically or numerically determined based on tolerances of attributed to the experimental determination of the wettability index and/or tolerances on characteristics used in determining predictions, etc..

Thereafter, the process <NUM> iteratively modifies <NUM> one or more of the input parameter values to the numerical aging simulation process <NUM>, and repeats <NUM> the numerical aging simulation process <NUM> until the values from the numerical aging simulation <NUM> agree <NUM> (Wp ≅ We ± T) with those from the experimental values indicating verification <NUM>.

As discussed above for <FIG>, the parameter values are one or more grain surface properties 33a' obtained by engine 33a that assigns mineral types to the grains and determines the surface properties for each of those mineral types, parameters such as fluid properties 33b, e.g., fluid density and viscosity of each expected fluid and fluid-fluid interfacial tension properties, chemical composition data of the fluids and affinity data of the fluid components for the particular mineral surfaces and the disjoining pressure for each mineral type. Iterative modification is accomplished by the system <NUM> incrementing one or more of the parameter values by a defined incremental value. Both the parameter value that is incremented and the incremental value amount can be system determined or user determined.

Referring to <FIG>, these prior art figures depict conventional understandings of oil blob and brine providing pinned contact angles conventions for an illustrative rock sample portion. (Taken from A Pore-Level Scenario for the Development of Mixed-Wettability in Oil Reservoirs, by<CIT> prepared for U. Department of Energy.

Embodiments of the subject matter and the functional operations described in this specification can be implemented in digital electronic circuitry, tangibly-embodied computer software or firmware, computer hardware (including the structures disclosed in this specification and their structural equivalents), or in combinations of one or more of them. Embodiments of the subject matter described in this specification can be implemented as one or more computer programs (i.e., one or more modules of computer program instructions encoded on a tangible non-transitory program carrier for execution by, or to control the operation of, data processing apparatus).

A program can be stored in a portion of a file that holds other programs or data (e.g., one or more scripts stored in a markup language document, in a single file dedicated to the program in question, or in multiple coordinated files (e.g., files that store one or more modules, sub-programs, or portions of code)). A computer program can be deployed so that the program is executed on one computer or on multiple computers that are located at one site or distributed across multiple sites and interconnected by a data communication network.

Generally, a computer will also include, or be operatively coupled to receive data from or transfer data to, or both, one or more mass storage devices for storing data (e.g., magnetic, magneto-optical disks, or optical disks), however, a computer need not have such devices.

Claim 1:
A computer implemented method for determining a wettability alteration of a physical rock sample in the presence of at least two fluids, the method being characterised in comprising:
performing a wettability alteration process (<NUM>) to age a digital representation of the physical rock sample for a time interval, the performing comprising:
setting up a rock sample simulation environment, comprising:
retrieving (<NUM>), by a computing system, the digital representation of the physical rock sample and assigning input parameters and conditions for the wettability alteration process, wherein the digital representation of the physical rock sample, includes a digital representation of a pore space and a grain space corresponding to the physical rock sample;
performing (<NUM>) a drainage simulation to establish a fluid phase distribution for user-specified conditions comprising a reservoir pressure and temperature;
calculating (<NUM>) by the computing system, a local curvature for each surface location in the pore space;
calculating (<NUM>), from the calculated local curvatures, a local capillary pressure and local disjoining pressure at each surface location in the pore space;
determining (<NUM>), from the calculated local curvatures, whether water file breakage will occur at the surface, comprising comparing local capillary pressure to a sum of local curvature based pressure and local disjoining pressure;
calculating (<NUM>) a spatial distribution of wettability using a subset of surface locations eligible for water-film breakage and locations in contact with a non-wetting phase obtained after the drainage simulation;
determining (<NUM>), for the subset of surface locations eligible for water-film breakage, a degree of wettability alteration based on local surface properties, local fluid chemical composition, and aging time;
classifying, by the computer system, a wettability of the surface locations corresponding to the physical rock based on the determination of local curvature; and
providing (<NUM>) a numerical prediction of surface wettability alteration and a resulting spatial distribution of wettability in the form of a contact angle at each surface location.