SYSTEM AND METHODS OF RECOVERING OIL

Description

BACKGROUND

Reservoirs of a subterranean formation can include heavy oil (herein referred to as “viscous oil”), bitumen, and tar. These terms all incorporate crude oil with large quantities of asphaltenes, e.g., greater than 8 wt%. Asphaltenes are one of the four primary families of chemical compounds in dead (degassed) crude oils. The other three families of chemical components are Saturated, Aromatics and Resin; these classes of compounds are referred to by the acronym SARA. Asphaltenes have three stable forms in crude oils as codified by the Yen-Mullins model, a hierarchical molecular and nanocolloidal model of asphaltenes. At low concentrations, asphaltenes are generally present as a true molecular solution. At moderate concentrations, asphaltenes are generally present as nanoaggregates, a nanocolloidal particle comprised of about 6 molecules. In viscous oils, asphaltenes are generally present as clusters, a nanocolloidal particle comprised of about 8 nanoaggregates.

Heavy oil viscosity depends primarily on three factors: temperature, gas-oil ratio (GOR) and asphaltene content. Asphaltic materials, e.g., viscous oil, bitumen, and/or tar, generally become much less viscous at elevated temperatures, but viscous at room temperature. Heating is sometimes used to produce viscous oil or bitumen. Generally, increasing GOR does not lower viscosity in the production of viscous oil because it is hard to mix gas with viscous oil in the subterranean formation, and increasing solution gas can cause bulk phase separation of asphaltenes and can clog porous media. Additionally, a 10 meter (vertical) tar mat generally exists underneath the heavy oil column. The tar mat can include a two phase system with trapped oil and a phase separated asphaltene-rich carbonaceous phase. The two-phase system can result from the settling of nanocolloidal asphaltenes, followed by Boycott convection to the base of the column.

Conventional oil recovery involves the use of water injection into the subterranean formation. Unfortunately, the location of the injector can result in reduction of oil recovery and/or fingering, thereby reducing efficiency of oil recovery. For example, an injector that is too far away from an oil-water contact can result in reduction of oil sweeping, while an injector that is injected at the oil-water contact can result in fingering, and tight emulsions, thereby clogging porous media used to recover the viscous oil.

Accordingly, improved methods of oil recovery are needed.

SUMMARY

The present disclosure generally provides methods of recovering oil. The methods include receiving data representing one or more physical characteristics of a subterranean formation. The data is collected by one or more devices deployed in or near the subterranean formation. A first model of the subterranean formation is obtained. The first model representing rock properties as a function of the location in the subterranean formation. An oil phase proximal to an oil-water contact is identified based on the first model of the subterranean formation and the one or more physical characteristics. The oil phase includes about 8 wt% to about 99 wt% asphaltene. A tool is disposed in the oil phase proximal to the oil-water contact of the subterranean formation. The tool is fluidly coupled to an aqueous fluid line and an organic fluid line. A first aqueous solvent is injected from the aqueous fluid line into the oil phase. An organic solvent is injected from the organic fluid line into the oil phase.

The present disclosure also generally provides methods of recovering oil. The methods include receiving data representing one or more physical characteristics of a subterranean formation. The data is collected by one or more devices deployed in or near the subterranean formation. A first model of the subterranean formation is obtained. The first model representing rock properties as a function of the location in the subterranean formation. An oil phase proximal to an oil-water contact is identified based on the first model of the subterranean formation and the one or more physical characteristics. The oil phase includes about 8 wt% to about 99 wt% asphaltene. A tool is disposed at or above the oil-water contact. The tool is fluidly coupled to an aqueous fluid line and an organic fluid line. A first aqueous solvent, having a first viscosity, is injected from the aqueous fluid line into an aqueous phase proximal to the oil-water contact. The first aqueous solvent includes a surfactant. The aqueous phase proximal to the oil-water contact including a second viscosity, in which the first viscosity is greater than the second viscosity.

The present disclosure also generally provides methods of recovering oil. The methods include receiving data representing one or more physical characteristics of a subterranean formation. The data is collected by one or more devices deployed in or near the subterranean formation. A first model of the subterranean formation is obtained. The first model representing rock properties as a function of the location in the subterranean formation. An oil phase proximal to an oil-water contact is identified based on the first model of the subterranean formation and the one or more physical characteristics. The oil phase includes about 8 wt% to about 99 wt% asphaltene. A tool is disposed at or above the oil-water contact. The tool is fluidly coupled to an aqueous fluid line and an organic fluid line. A first aqueous solvent, having a first viscosity, is injected from the aqueous fluid line into an aqueous phase proximal to the oil-water contact. The first aqueous solvent includes a surfactant. The aqueous phase proximal to the oil-water contact including a second viscosity, in which the first viscosity is greater than the second viscosity. An organic solvent is injected from the organic fluid line above the first aqueous solvent.

The following description and the appended figures set forth certain features for purposes of illustration.

BRIEF DESCRIPTION OF DRAWINGS

So that the manner where the above recited features may be understood in detail, a more particular description, briefly summarized above, may be had by reference to example aspects, some of which are illustrated in the appended drawings.

FIG. 1 is a schematic view of a subterranean formation having a plurality of data acquisition tools disposed at various locations in the formation, according to embodiments of the present disclosure.

FIG. 2 is a functional block diagram of an exemplary reservoir modeling software framework, according to embodiments of the present disclosure.

FIG. 3 is a functional block diagram of an exemplary computer workstation suitable for embodying the reservoir modeling software framework of FIG. 2, according to embodiments of the present disclosure.

FIG. 4 is a diagrammatic representation of a method flow of recovering oil, according to embodiments of the present disclosure

FIG. 5 is a diagrammatic representation of a method flow of recovering oil, according to embodiments of the present disclosure.

DETAILED DESCRIPTION

One or more specific embodiments of the present disclosure will be described herein. These described embodiments are only examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers’ specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

The present disclosure relates to systems and methods of recovering oil. The present disclosure can increase oil recovery efficiency by injecting an organic solvent from an organic fluid line into the oil phase to dissolve dissolved and/or dispersed asphaltenes in the subterranean formation, thereby reducing clogging of porous media used to recover the viscous oil. Moreover, the present disclosure can increase oil recovery efficiency by injecting an aqueous solvent having a greater viscosity than the aqueous phase, e.g., aquipher layer, at or above the oil-water contact, thereby preventing fingering and concurrently maintaining sweeping of the viscous oil in the reservoir. The present disclosure can also determine the location of the oil-water contact using one or more of modeling processes to ensure the location of the tool, e.g., aqueous injector and/or organic injector, is disposed at or slightly above the oil-water contact to provide efficient oil recovery.

The exemplary subterranean structure 304, as shown in FIG. 1, may include several formations or layers, including, but not limited to: a shale layer 306a, a carbonate layer 306b, a shale layer 306c, a sand layer 306d, and an aquipher layer 306e. A fault 307 can extend through the layers 306a, 306b, and 306e. Viscous oil is contained within the carbonate layer 306b, aqueous fluids are contained in the aquipher layer 306e. The seismic surveying tools may be adapted to derive a structural map of the reservoir as well as rock and fluid properties of the formation. While a specific subterranean formation with specific geological structures is depicted, it will be appreciated that the structure may contain a variety of geological formations, sometimes having extreme complexity. In some locations, typically below the oil-water contact 310, fluid may occupy pore spaces of the formations.

One or more wells may extend into the subterranean formation. The wells can be provided with tools that are used to drill the well and/or analyze the subterranean formation and/or hydrocarbon fluids located therein for evaluation purposes. For example, a drilling tool 302b can be deployed from a drilling rig and advanced into the earth along a desired path as shown in FIG. 1. Fluid, such as drilling mud or other drilling fluids, e.g., aqueous fluids and/or organic fluids, may be pumped down the wellbore through the drilling tool and out the drilling bit. The drilling fluid flows through the annulus between the drilling tool and the wellbore and out the surface, carrying away earth loosened during drilling. The drilling fluids return the earth to the surface and seal the wall of the wellbore to prevent fluid in the surrounding earth from entering the wellbore and causing a blowout. During the drilling operation, the drilling tool may perform downhole measurements to investigate downhole conditions, e.g., the location of the carbonate layer 306b, the oil-water contact 310, and/or the location of the aquipher layer 306e. The drilling tool may also be used to take core samples of the formation.

In some cases, the drilling tool can be removed and a wireline tool 302c can be deployed into the wellbore to perform core sampling or additional downhole testing, such as analysis of the properties of the formation, sampling of formation fluids, analysis of the properties of the formation fluids, e.g., viscosity, and/or formation fluid locations within the subterranean formation. The wireline tool 302c may be positioned at various depths in the wellbore to provide a survey or other information relating to the subterranean formation. The wireline tool 302c (and/or the drilling tool 302b) can perform a variety of operations, including, but not limited to: well logging operations, downhole fluid sampling, core sampling, and downhole fluid analysis.

Well logging operations measure rock and fluid properties of the formation (such as lithology, porosity, permeability, oil and water saturation, and a combination thereof). Lithology represents the rock type and is typically measured by well logging operations such as natural gamma, neutron, density, photoelectric, resistivity and/or combinations thereof. Porosity represents the amount of pore space in the rock and is typically measured by neutron or gamma ray logging or NMR measurements. Permeability represents the quantity of fluid (usually hydrocarbon) that can flow from the rock as a function of time and pressure. Formation testing is so far the only direct downhole permeability measurement. In case of its absence, which is common in most cases, permeability estimation may be derived from other measurements, such as porosity, NMR, sonic, by empirical correlations. Water saturation represents the fraction of the pore space occupied by water and is typically measured using an instrument that measures the resistivity of the rock. Oil saturation represents the fraction of the pore space occupied by oil and is typically measured by neutron logging or dielectric scanning.

Downhole fluid sampling operations extract and store one or more live fluid samples within the tool. Core sampling operations extract one or more core samples from the formation. Each core sample is isolated and identified from other core samples. There are several types of core samples that can be recovered from the wellbore, including but not limited to: full-diameter cores, oriented cores, native state cores and sidewall cores. In an exemplary embodiment, the coring tool obtains one or more sidewall cores from the formation adjacent the wellbore. Core samples can also be acquired while the well is being drilled. Coring operations can be run in combination with other suitable logging operations (such as gamma ray logging) to correlate with openhole logs for accurate, real-time depth control of the coring points.

Downhole fluid analysis operations extract live fluid from the formation adjacent the wellbore and derive properties (e.g., GOR, oil-based-mud contamination, saturation pressure, live fluid density, live fluid viscosity, and compositional component concentrations, etc.) that characterize the live fluid at the pressure and temperature of the formation. For example, the Quicksilver probe and InSitu fluid analyzer commercially available from Schlumberger can be used to perform such downhole fluid analysis operations.

Laboratory analysis can be performed on the core samples and/or live fluid samples gathered from the reservoir. The live fluid samples may be reconditioned to the formation reservoir and pressure at the sample depth and subjected to analytical measurements (e.g., GOR, oil-based-mud contamination, fluid composition) that replicate the downhole fluid analysis measurements. The results of the laboratory measurements can be compared to the results of the corresponding downhole measurements for chain of custody verification. In the case of verification failure, actions can be taken to identify and correct the cause of the failure, which can arise from hardware failure of the downhole fluid analysis tool or laboratory tool, and inappropriate sampling, sample reconditioning and/or sample transfer techniques. The core sample can be analyzed in the laboratory by many different means. For example, such analysis can include bulk measurements (e.g., porosity, grain density, permeability, residual saturation, etc.) to measure properties of the core sample. In the case that the core sample includes movable hydrocarbons, hydrocarbon fluid can be extracted from the core sample by centrifuging the core sample. In the case that the core sample is non-movable bitumen, hydrocarbon fluid can be extracted from the bitumen core sample using a solvent. In either case, the composition of the extracted hydrocarbon fluid can be analyzed by geochemical analysis, which can be carried out by a variety of techniques including, but not limited to: gas chromatography techniques, Saturates-aromatics-resins-asphaltenes (SARA) analysis; optical spectroscopy in the ultraviolet, visible, and near-infrared regions; infrared spectroscopy; fluorescence spectroscopy; Raman spectroscopy; liquid chromatography, pyrolysis experiments with gas chromatography or other detection methods; isotope analysis; and/or nuclear magnetic resonance (NMR) spectroscopy using various nuclei (13C, 1H, etc.).

Drilling may continue until the desired total depth is reached. Steel casing may be run into the well to a desired depth and cemented into place along the wellbore wall. A surface unit (not shown) may be used to communicate with the drilling tool 302b and/or wireline tool 302c and possibly to offsite operations. The surface unit may be capable of communicating with the drilling tool 302b and/or wireline tool 302c to send commands to the respective tool, and to receive data therefrom. The surface unit may be provided with computer facilities for receiving, storing, processing, and/or analyzing data from the reservoir. The surface unit collects data generated during the drilling or logging operation and produces data output which may be stored or transmitted. Computer facilities, such as those of the surface unit, may be positioned at various locations about the reservoir and/or at remote locations.

After the drilling operation is complete, the well may then be prepared for production. Completions equipment may be deployed into the wellbore to complete the well in preparation for the production of hydrocarbons therethrough. Such completions equipment can include a production tool 302d, such as a packer, artificial lift apparatus, sand control device, or a combination thereof, as shown in FIG. 1. Hydrocarbons are allowed to flow from the downhole reservoir through the completions equipment to the surface. Production facilities positioned at surface locations may collect the hydrocarbons from the wellsite(s). Fluid drawn from the subterranean reservoir(s) passes to the production facilities via transport mechanisms, such as tubing. Various equipment may be positioned about the reservoir to monitor oilfield parameters, to manipulate the operations and/or to separate and direct fluids from the wells. Surface equipment and completion equipment may also be used to inject fluids into reservoirs, either for storage or at strategic points to enhance production of the reservoir. As fluid passes to the surface, various dynamic measurements, such as fluid flow rates, pressure and composition may be monitored. These parameters may be used to determine various characteristics of the subterranean formation.

While only simplified wellsite configurations are shown, it will be appreciated that the reservoir may cover a portion of land, sea and/or water locations that hosts one or more wellsites. Production may also include injection wells 302e for added recovery. In some embodiments, the injection wells 302e can include injecting an aqueous solvent and/or an organic solvent into the wellbore, as described herein. One or more gathering facilities may be operatively connected to one or more of the wellsites for selectively collecting downhole fluids from the wellsite(s).

The information generated by the operations depicted in FIG. 1 and summarized above may be used to evaluate the reservoir, and make decisions concerning development and production. Such decisions may involve well planning, well targeting, well completions, operating levels, production rates and other operations and/or operating parameters.

Seismic data may be used by a geophysicist to determine characteristics of the subterranean formations and features. Well-logging data as well as the data resulting from core analysis, laboratory fluid analysis and downhole fluid may characterize the porosity and permeability of the rock of the formation as well as viscosity, density and compositions of the fluids contained therein. Such information may be used by a geologist to determine various characteristics of the subterranean formation. Production data, if available, may be used by a reservoir engineer to determine fluid flow reservoir characteristics.

The information analyzed by the geophysicist, geologist and/or the reservoir engineer may be used in conjunction with one or more computer-based reservoir modeling applications that model the behavior of the geological formations, downhole reservoirs, wellbores, surface facilities as well as other portions of the operations. Examples of these reservoir modeling applications are shown in U.S. Pat. No. 5,992,519; WO2004/049216; WO1999/064896; U.S. Pat. No. 6,313,837; US2003/0216897; U.S. Pat. No. 7,248,259; US2005/0149307; US2006/0197759; U.S. Pat. No. 6,980,940; US2004/0220846; and U.S. Pat. No. 6,801,197; all herein incorporated by reference in their entireties.

In another example, the information generated by the operations depicted in FIG. 1 can be used for decisions that optimize production of the reservoir, such as decisions with respect to drilling new wells, re-completing existing wells or alter wellbore production. Oilfield conditions, such as geological, geophysical and reservoir engineering characteristics may have an impact on operations, such as risk analysis, economic valuation, and mechanical considerations for the production of subsurface reservoirs. Data from one or more wellbores may be analyzed to plan or predict various outcomes at a given wellbore. In some cases, the data from neighboring wellbores, or wellbores with similar conditions or equipment, may be used to predict how a well will perform. There are usually a large number of variables and large quantities of data to consider in analyzing operations involving the reservoir. It is, therefore, often useful to model the behavior of the reservoir to determine a desired course of action. During the ongoing operations, the operating parameters may need adjustment as oilfield conditions change and new information is received.

Embodiments of the present disclosure may include the operations described above with respect to FIG. 1 as part of a workflow, e.g., as shown in FIGS. 4 and 5 that effectively recover oil of a subterranean formation. The workflow may employ a reservoir modeling software framework 100 as illustrated in FIG. 2.

The software framework 100 may include a data store 102 that stores the data generated from the data gathering operations of FIG. 1 as illustrated schematically in FIG. 2. Such data can include well log data (e.g. petrophysical data), seismic analysis results, laboratory core and fluid analysis results, and downhole fluid analysis results that pertain to a specific formation of interest as well as historical data for other formations that are related to the formation of interest in some meaningful way. The particular data gathering operations may be dictated by a reservoir assessment plan as depicted schematically in FIG. 2. The goal of the reservoir assessment plan may be to derive an understanding of the structure and stratigraphy of the formation of interest as well as a forecast of the hydrocarbons that are contained in the formation of interest. Risk and uncertainty can be accounted for in particular tests and analyses that are part of the reservoir assessment plan, the reservoir modeling that is accomplished by the software framework 100, and the summary information and decisions that are based thereon.

A geologic modeler 104 operates on the data stored in the data store 102 to generate a three-dimensional geological model 106 of the formation of interest. The three-dimensional geological model 106 can be a framework that provides a description of the structure and stratigraphy of the formation of interest. In an exemplary embodiment, the geological model 106 provides a basic description of the formation of interest in terms of dimensions and unconformities (e.g., fractures, layers, oil-water contacts, and permeability barriers). The geological model may include the following information for the formation of interest: top reservoir surface, which can be a constant value or a complex surface interpolated from well markers and/or geophysics; base reservoir surface, which can be derived as an offset (constant or variable) from the top reservoir surface or a complex surface interpolated from well markers and/or geophysics; intra-reservoir surface, as needed and similar to the top and base reservoir surfaces; reservoir boundaries, which can be derived from bounding faults, pinchouts, designated extent, etc.; and rock and fluid properties such as facies (which can be derived from geostatistical modeling or object modeling) as well as porosity, permeability, relative permeabilities, water saturation, net-to-gross ratio, capillary pressure (which can be derived from inversion of seismic data, core analyses and well logs and/or historical data)

The geological model 106 may be constructed of a large number of grid cells, with each grid cell typically populated with a reservoir property that may include rock type, porosity, permeability, initial interstitial fluid saturation, and relative permeability and capillary pressure functions. The geographical model can be derived from an intermediate model, such as a stratigraphic model. The grid cells can be structured or unstructured. Structured grid cells have similar shape and the same number of sides or faces. Common structured grid cells may be defined in Cartesian or radial coordinate systems, in which each cell has four sides in two dimensions or six faces in three dimensions. Unstructured grid cells may be made up of polygons (polyhedra in three dimensions) having shapes, sizes, and number of sides or faces that can vary from place to place. One type of unstructured grid cell includes the Voronoi grid cell. Each Voronoi grid cell may be associated with a node and a series of neighboring cells. The Voronoi grid may be locally orthogonal in a geometrical sense; that is, the cell boundaries may be normal to lines joining the nodes on the two sides of each boundary. For this reason, Voronoi grid cells may also commonly be called perpendicular bisection (PEBI) grid cells. Other types of unstructured grid cells can also be used.

Reservoir simulations may be performed with a coarser grid system as the direct use of fine-grid models for reservoir simulation is not generally feasible because their fine level of detail places prohibitive demands on computational resources. Therefore, the software framework 100 employs one or more gridding and upscaling modules (two shown as 108A and 108B) that scale up the fine-grid geologic model 106 to a coarser reservoir simulation grid 110 while preserving, as much as possible, the fluid flow characteristics of the fine-grid geological model 106. The module 108A upscales a structured fine-grid geographical model 106 to the coarser reservoir simulation grid 110. Examples of suitable upscaling procedures for use in module 108A are provided in the following papers: Wen et al., “Upscaling Hydraulic Conductivities in Heterogeneous Media: An Overview,” Journal of Hydrology, Vol. 183 (1996) 9-32; Begg et al., “Assigning Effective Values to Simulator Gridblock Parameters for Heterogeneous Reservoirs,” SPE Reservoir Engineering (November 1989) 455-465; Durlofsky et al., “Scale Up of Heterogeneous Three Dimensional Reservoir Descriptions,” Paper SPE 30709 presented at the Annual Technical Conference and Exhibition, Dallas, Tex. (Oct. 22-25, 1995); and Li et al., “Global Scale-up of Reservoir Model Permeability with Local Grid Refinement”, Journal of Petroleum Science and Engineering, Vol. 14 (1995) 1-13. U.S. Pat. No. 6,106,561 to Farmer, commonly assigned to assignee of the present application and herein incorporated by reference in its entirety, describes a structured gridding and upscaling methodology that can be carried out by module 108A. The module 108B upscales an unstructured fine-grid geographical model 106 to the coarser reservoir simulation grid 110. Examples of suitable upscaling procedures for use in module 108B are provided by M. Prevost et al., “Unstructured 3D Gridding and Upscaling for Coarse Modeling of Geometrically Complex Reservoirs,” Petroleum Geoscience, October 2005, v. 11; no. 4, pgs. 339-345 as well as U.S. Pat. No. 6,826,520 to Khan et al. and U.S. Pat. No. 6,018,497 to Gunasekera, herein incorporated by reference in their entireties. The resultant reservoir simulation grid 110 may be constructed from a coarse grid of cells that are associated with petrophysical properties such as porosity, permeability, initial interstitial fluid saturation, and relative permeability and capillary pressure functions. For a fractured reservoir, a dual-porosity model and/or a dual-permeability model can be used. Local grid refinements (a finer grid embedded inside of a coarse grid) can also be used, for example to more accurately represent the near wellbore multi-phase flow affects.

The software framework 100 may further include a fluid property modeler 112 that operates on the data stored in the data store 102 to generate a fluid property model 114 that characterizes the fluid properties of the formation of interest. The fluid property modeler 112 may employ a particular equation of state model, referred to herein as the FHZ EOS, that derives property gradients, pressure gradients and temperature gradients as a function of depth in the formation of interest. These gradients may be incorporated as part of the fluid property model 114. The property gradients derived from the FHZ EOS may include mass fractions, mole fractions, molecular weights, and specific gravities for a set of pseudocomponents of the formation fluid. Such pseudocomponents may include a heavy pseudocomponent representing asphaltenes in the formation fluid, a second distillate pseudocomponent that represents the non-asphaltene liquid fraction of the formation fluid, and a third light pseudocomponent that presents gases in the formation fluid. The pseudocomponents derived from the FHZ EOS can also represent single carbon number (SCN) components as well as other fractions or lumps of the formation fluid (such as a water fraction) as desired. The FHZ EOS can predict compositional gradients with depth that take into account the impacts of gravitational forces, chemical forces, thermal diffusion, etc. as taught in U.S. Patent Appl. Nos. 61/225,014 and 61/306,642, herein incorporated by reference in its entirety. Other applications of the FHZ EOS have been described in U.S. Pat. No. 7,822,554 and U.S. patent application Ser. Nos. 12/209,050; 12/352,369; 12/990,980; 12/483,813; 61/282,244; 61/387,066; 12/752,967; and 61/332,595, herein incorporated by reference in their entireties. For some cases, one or more terms of the FHZ EOS dominate and the other terms can be ignored. For example, in low GOR black oils, the gravity term of the FHZ EOS dominates and the term related to chemical forces (solubility) and thermal diffusion (entropy) can be ignored.

The compositional gradients produced by the FHZ EOS can be used in conjunction with a Flory-Huggins solubility model to derive a concentration profile of asphaltene pseudocomponents (e.g., asphaltene nanoaggregates and larger asphaltene clusters) and corresponding aggregate size of asphaltenes as a function of depth in the formation of interest as taught in U.S. Patent Appl. Nos. 61/225,014; 61/306,642; and 61/332,595, herein incorporated by reference in their entireties. This information can also be incorporated into the fluid property model 114.

The asphaltene concentration gradient can also be used to predict gradients for fluid properties (such as fluid density and fluid viscosity) that relate to asphaltene content. For predicting viscosity, the predictions can be based on the empirical correlation of the form proposed by Lohrenz, Bray and Clark in “Calculating Viscosity of Reservoir Fluids from their Composition,” JPT, October 1964, pp 1171-117, or the empirical correlation of the form proposed by Pedersen et al. in “Viscosity of Crude Oils,” Chemical Engineering Science Vol 39, No 6, pp 1011-1016, 1984. These fluid property gradients can also be incorporated into the fluid property model 114.

In an exemplary embodiment, the FHZ EOS utilized by the fluid property modeler 112 may be tuned in accordance with laboratory fluid data or downhole fluid analysis data that is stored in the data store 102 and describes the fluids of the formation of interest. Corrections for drilling fluid contamination may be necessary. An example of such corrections is described in U.S. patent application Ser. No. 12/990,980.

The fluid property model 114 may be stored in the data store 102 and may include data that describes fluid properties as a function of location in the formation of interest. In an exemplary embodiment, the fluid property model 114 may include one or more of the following: component mass fractions, molecular weights and critical properties (pressure, temperature, volume) as a function of location in the formation of interest; component acentric factors, Z-factor, volume shift parameters, reference density; binary interaction coefficients; and formation volume factors, fluid density, fluid viscosity, and asphaltene concentration and aggregate sizes as a function of location in the formation of interest. In an exemplary embodiment, a fluid property model may include parameters that represent the continuous changes in respective fluid properties as a function of position along one or more wellbores that traverse a formation of interest.

The framework 100 may further include a module 116 that maps or interpolates the fluid properties of the formation fluids as represented by the fluid property model 114 to the grid cells of the reservoir simulation grid 110. In an exemplary embodiment, the fluid properties for a given simulation grid cell may be interpolated from the fluid properties of the fluid property model corresponding to the nearest formation locations. Such interpolation may be carried out separately over the grid cells for each compartment of the formation. For example, consider a trend such as asphaltene concentration increasing with depth within from an initial value and rate of change within a reservoir compartment. That trend may occur, with the magnitude predicted by the EOS, but the trend may stop abruptly at the end of the compartment. Such trend parameters can be used to interpolate the asphaltene concentration over the grid cells of this compartment. In the next compartment, the trend may start over with a different initial value and a different rate of change. These different trend parameters can be used to interpolate the asphaltene concentration over the grid cells of the next compartment. In performing the interpolation, continuous changes of a respective fluid property value may be mapped into discrete values, and the cells may then be populated with such discrete values. That is to say, the smooth variation of a respective fluid property values may be binned into something that looks like a stairstep variation.

The framework 100 may further include an evaluation module 118 that provides the user with the capability to review and analyze the information stored in the reservoir simulation grid 110 in order to understand the structural properties and fluid properties of the formation of interest. The evaluation module 118 can provide for rendering of 3-D representations of properties of the formation of interest for use in full-field visualization. The evaluation module 118 can also display 2-D representations of properties of the formation of interest, such as cross-sections and 2-D radial grid views. In an illustrative embodiment, the evaluation module 118 can be used to characterize the reservoir (e.g., evaluate the static state of the reservoir before any production) and identify, confirm or modify reserves forecasts for the formation of interest and/or any uncertainties and risk factor associated therewith. The information provided by the evaluation module 118 can be used to update the reservoir assessment plan in the event that uncertainties or risks are unacceptable or new information is gathered. Changes or additions to the tests and analyses of the assessment plan can be planned and carried out in order to acquire additional data, and the modeling and simulation operations of the modules of the framework 100 can be repeated in an attempt to seek a more certain understanding of the formation of interest.

When assessment is complete, a reservoir development plan can be defined. The reservoir development plan may store information for producing hydrocarbons from the formation of interest, such as the number and location of wells, the completion apparatus of wells, artificial lift mechanisms, water injection, water flooding, steam injection, hydraulic fracturing for shale gas, pipeline systems, facilities, and the expected production of fluids (gas, oil, water) from the formation. Details of the reservoir development plan may be input to a reservoir simulator module 120 of the framework 100. The reservoir simulator 120 may derive computational equations and associated time-varying data that represent the details of reservoir development plan over time. Examples of such computational equations and associated time-varying data is described in U.S. Patent Publ. No. 2010/0004914 to Lukyanoc et al., commonly assigned to assignee of the present application and herein incorporated by reference in its entirety. The reservoir simulator 120 may utilize the computational equations and associated time varying data representing the reservoir development plan together with the rock properties and fluid properties stored in the reservoir simulation grid 110 upon completion of reservoir characterization (or updated thereafter) to derive the pressure and fluid saturations (e.g., volume fractions) for each cell as well as the production of each phase (e.g., gas, oil, water) over a number of time steps.

In an exemplary embodiment, the reservoir simulator 120 carries out finite difference simulation, which is underpinned by three physical concepts: conservation of mass, isothermal fluid phase behavior, and the Darcy approximation of fluid flow through porous media. Thermal simulation (which may be used for heavy oil applications) adds conservation of energy to this list, allowing temperatures to change within the reservoir. The PVT properties of the oil and gas phases of the reservoir fluids of the grid may be fitted to an equation of state (EOS), as a mixture of components in order to dynamically track the movement of both phases and components in a formation of interest. Changes in saturation of three phases (gas, oil, and water) as well as pressure of each phase may be calculated in each cell at each time step. For example, declining pressure in a reservoir may result in gas being liberated from the oil. In another example, with increasing pressure in the reservoir (e.g., as a result of water or gas injection), gas may be re-dissolved into the oil phase. Details of exemplary operations for carrying out the finite difference simulation are set forth in U.S. Pat. No. 6,230,101 to Wallis, commonly assigned to assignee of the present application and herein incorporated by reference in its entirety. Alternatively, finite element simulation techniques and/or streamline simulation techniques can be used by the reservoir simulator 120. The EOS employed by the simulator 120 may be based on the FHZ EOS that is employed by the fluid property modeler 112 as described above. The FHZ EOS can be extended to derive and simulate a variety of properties of the reservoir fluid of the formation, including: PVT properties (e.g., phase envelope, pressure-temperature (PT) flash, constant composition expansion (CCE), differential liberation (DL), constant volume depletion (CVD)); gas hydrate formation; wax precipitation; asphaltene precipitation; and scaling.

Examples of equations for extending the FHZ EOS model for predicting gas hydrate formation are described in H. J. Ng et al., “The Measurement and Prediction of Hydrate Formation in Liquid Hydrocarbon-Water Systems,” Ind. Eng. Chem. Fund., 15, 293 (1976); H. J. Ng et al., “Hydrate Formation in Systems Containing Methane, Ethane, Propane, Carbon Dioxide or Hydrogen Sulfide in the Presence of Methanol,” Fluid Phase Equil., 21, 145 (1985); H. J. Ng et al., “New Developments in the Measurement and Prediction of Hydrate Formation for Processing Needs,” International Conference on Natural Gas Hydrates, Annals of the New York Academy of Sciences Vol. 715, 450-462 (1994); J. Y. Zuo et al. “Representation of Hydrate Phase Equilibria in Aqueous Solutions of Methanol and Electrolytes Using an Equation of State,” Energy and Fuels, 14, 19-24 (2000); and J. Y. Zuo et al., “A Thermodynamic Model for Gas Hydrates in the Presence of Salts and Methanol,” Chem. Eng Comm., 184, 175-192 (2001), herein incorporated by reference in their entireties.

Examples of equations for extending the FHZ EOS model for predicting wax precipitation are described in H. Alboudwarej et al., “Effective Tuning of Wax Precipitation Models,” 7th International Conference on Petroleum Phase Behavior and Fouling, Asheville, N.C., (2006); J. Y. Zuo et al., “An improved thermodynamic model for wax precipitation from petroleum fluids,” Chemical Engineering Science, 56, 6941 (2001); and J. Y. Zuo et al., “Wax Formation from Synthetic Oil Systems and Reservoir Fluids,” 11th International Conference on Properties and Phase Equilibria for Product and Process Design, Crete, Greece, May 20-25, (2007), herein incorporated by reference in their entireties.

An example of equations for extending the FHZ EOS model for predicting asphaltene precipitation is described in J. Du et al., “A Thermodynamic Model for the Predictions of Asphaltene Precipitation,” Petroleum Science and Technology, 22, 1023 (2004), herein incorporated by reference in its entirety.

The evaluation module 118 can provide for construction of 3-D representations of the properties of the formation of interest over time as output by the simulator 120 for use in full-field evaluation. The evaluation module 118 can also provide 2-D representations of properties of the formation of interest over time as output by the simulator 120, such as cross-sections and 2-D radial grid views. For example, the evaluation module 118 can be used to evaluate the dynamic state of the reservoir during product and confirm or modify production forecasts and/or any uncertainties and risk factor associated therewith. The information provided by the evaluation module 118 can be used to update the reservoir development plan in the event that uncertainties or risks are unacceptable or new information is gathered. Changes or additions to equipment and operations of the reservoir development plan can be planned, and the modeling and simulation operations of the modules of the framework 100 can be repeated in an attempt to seek a more certain understanding of the planned production from the formation of interest over time.

When the reservoir development plan is complete, production from the reservoir may be carried out in accordance with the reservoir development plan, as described here, referring to FIGS. 4 and 5. Production monitoring equipment can be used to gather information (e.g., historical field production pressures, pipelines pressures and flow rates, and a combination thereof). The reservoir development plan can be updated based upon such new information, and the reservoir simulator 120 can employ “history matching” where historical field production and pressures are compared to calculated values. The parameters of the reservoir simulator 120 may be adjusted until a reasonable match is achieved on a reservoir basis and usually for all wells. In an exemplary embodiment, producing water cuts or water-oil ratios and gas-oil ratios are matched.

In an exemplary embodiment, the reservoir modeling software framework 100 of FIG. 2 may be embodied as software modules executing on a computer workstation as shown in FIG. 3. The software modules can be persistently stored in the hard disk drive(s) of the workstation and loaded into memory for execution by the CPU(s) of the workstation. One or more of the modules of the framework 100, such as the geological model 104, gridding modules 108A, 108B, fluid property model 112, and fluid property mapper module 116 can be integrated as a part of the framework 100 or alternatively as plug-in module. A plug-in module may include software that adds specific capabilities to a larger host application (the framework 100). The host application may provide services which the plug-in can use, including, but not limited to, a way for plug-ins to register themselves with the host application and a protocol for the exchange of data with plug-ins. Plug-ins may depend on the services provided by the host application and might not work by themselves. Conversely, the host application may operate independently of the plug-ins, making it possible for end-users to add and update plug-ins dynamically without needing to make changes to the host application.

In alternate embodiments, the reservoir modeling software framework 100 of FIG. 2 can be embodied in a distributed computing environment (such as a computing cluster or grid) or in a cloud computing environment.

Now referring to FIG. 4, a method 400 of recovering oil is shown. At operation 410, data representing one or more physical characteristics of a subterranean formation is received by a computing workstation. In some embodiments, the data can be collected by one or more devices, e.g., measurement tools described herein, which are deployed in and/or near the subterranean formation. For example, the data can include a wireline tool 302c as described herein.

At operation 420, a first model of the subterranean formation is obtained. The first model can include the 3D geologic model 106, as described above. The first model represents rock properties as a function of location in the subterranean formation, as described herein. For example, the first model can represent the location of an oil-water contact location in the subterranean formation.

At operation 430, an oil phase proximal to an organic-aqueous phase based on the first model of the subterranean formation and the one or more physical characteristics. The oil phase comprises about 8 wt% to about 99 wt% asphaltene, e.g., about 10 wt% to about 99 wt%, about 20 wt% to about 99 wt%, about 30 wt% to about 99 wt%, about 40 wt% to about 99 wt%, about 50 wt% to about 99 wt%, about 60 wt% to about 99 wt%, about 70 wt% to about 99 wt%, about 80 wt% to about 99 wt%, or about 90 wt% to about 99 wt%. In some embodiments, the oil phase may proximal to the oil-water contact may include an oil phase located about 1 meters (m) to about 100 m to the oil-water contact.

In some embodiments, identifying the oil-water contact includes generating a second model of the subterranean properties. The second model can represent fluid properties based on a location in the subterranean formation. For example, the second model can characterize asphaltene concentration based on the location in the subterranean formation. In some embodiments, the second model can include the fluid property model 114, as described above. Reservoir compartments of the subterranean formation can be identified based, at least partially, on the asphaltene concentration based on the location of the subterranean formation. For example, reservoir compartments including tar mats can be identified based on the asphaltene concentration in the location of the subterranean formation. In some embodiments, the reservoir compartments can include the reservoir simulation grid 110 as described herein. In some embodiments, the oil-water contact can be identified based on the reservoir compartments identified. For example, the oil-water contact can be identified by determining a first reservoir compart of the carbonate layer 306b, and a second compartment of the aquipher layer 306e.

At operation 440, a tool is disposed in the oil phase of the subterranean formation. The tool can include an injector tool capable of injecting one or more solvents, e.g., aqueous solvent and/or organic solvents. In some embodiments, the tool can be fluidly coupled to an aqueous fluid line and an organic fluid line. The aqueous fluid line is fluidly coupled to a first aqueous solvent. In some embodiments, the first aqueous solvent can include water. The water can be treated with one or more additives. In some embodiments, the one or more additives can include gelling agents, biopolymers, functionalized biopolymers, synthetic polymers (e.g., branched and/or linear), non-emulsifiers, silica (e.g., nan-silica and/or colloidal silica), viscoelastic surfactants, and combinations thereof. In some embodiments, the biopolymers can include guar, xanthan, diutan, starch, cellulose, and/or derivatives thereof. In some embodiments, the functionalized biopolymers can include ethoxylated biopolymers, propoxylated biopolymers, methylated biopolymers, carboxymethylated biopolymers, or combinations thereof. For example, the functionalized biopolymers can include hydroxyethyl cellulose, hydroxypropyl guar, methylcellulose, carboxymethyl cellulose, carboxymethyl hydroxypropyl guar, or combinations thereof. In some embodiments, the synthetic polymers can include polyacrylamide polymers, acrylamide copolymers, 2-acylamido-2-methyl-1-propanesulfonic acid, polyvinylpyrrolidone, or combinations thereof. In some embodiments, the non-emulsifiers can include ethylene glycol monobutyl ether, decyl octyl glycosides, fatty acid derivative polymers, and/or combinations thereof. For example, the first aqueous solvent can include water treated with ethylene glycol monobutyl ether.

The organic fluid line is fluidly coupled to an organic solvent. The organic solvent can include one or more of xylene, maleic acid dicarboxylic ester, adipic acid dicarboxylic acid, succinic ester, acetic ester, formic ester, toluenes, benzenes, hexenes, and/or combinations thereof. The organic fluid line can inject the organic solvent into the wellbore at an injection rate of about 100 barrels per day (bpd) to about 100000 bpd, e.g., about 100 bpd to about 10,000 bpd, about 1,000 bpd to about 10,000 bpd, or about 2,000 bpd to about 5,000 bpd.

At operation 450, the first aqueous solvent is injected into the oil phase of the subterranean formation. In some embodiments, the first aqueous solvent can be injected at a flow rate of about 100 barrels per day (bpd) to about 100000 bpd, e.g., about 100 bpd to about 10,000 bpd, about 1,000 bpd to about 10,000 bpd, or about 2,000 bpd to about 5,000 bpd . In some embodiments, the first aqueous solvent can be injected at a pressure suitable to maintain the flow rate of about 100 bpd to about 100000 bpd. In some embodiments, the first aqueous solvent can be injected at a location that is about m to about m above the oil-water contact. Without being bound by theory, by injecting the first aqueous solvent in the oil phase, e.g., the carbonate layer 306b, of the subterranean formation, an increase net sweeping of the carbonate layer 306b can occur, thereby improving oil recovery in the subterranean formation.

At operation 460, the organic solvent is injected into the oil phase of the subterranean formation. In some embodiments, the organic solvent can be injected at a flow rate of about 100 barrels per day (bpd) to about 100000 bpd, e.g., about 100 bpd to about 10,000 bpd, about 1,000 bpd to about 10,000 bpd, or about 2,000 bpd to about 5,000 bpd . In some embodiments, the organic solvent can be injected at a pressure greater than the formation pressure, in which the pressure does not exceed a pressure suitable to fracture the formation. In some embodiments, the organic solvent can be injected at a location that is about 0.001 m to about 100 m above the oil-water contact, e.g., about 0.001 m to about 90 m, about 0.001 m to about 80 m, about 0.01 m to about 70 m, about 0.1 m to about 60 m, or about 1 m to about 50 m. Without being bound by theory, by injecting the organic solvent in the oil phase, e.g., the carbonate layer 306b, of the subterranean formation, tight emulsions formed as a result of the first aqueous solvent injection may be dispersed and/or degraded, thereby preventing clogging in the porous media during oil recovery.

In some embodiments, operating 460 can include injecting a second aqueous solvent fluidly coupled to the aqueous fluid line into the oil phase of the subterranean formation. In some embodiments, the second aqueous solvent can be injected at a flow rate of about 100 barrels per day (bpd) to about 100000 bpd, e.g., about 100 bpd to about 10,000 bpd, about 1,000 bpd to about 10,000 bpd, or about 2,000 bpd to about 5,000 bpd. In some embodiments, the second aqueous solvent can be injected at a location that is about 0.001 m to about 100 m above the oil-water contact, e.g., about 0.001 m to about 90 m, about 0.001 m to about 80 m, about 0.01 m to about 70 m, about 0.1 m to about 60 m, or about 1 m to about 50 m.

In some embodiments, the second aqueous solvent can include water. The water can be treated with one or more additives to increase the viscosity of the first aqueous solvent. In some embodiments, the one or more additives can include gelling agents, biopolymers, functionalized biopolymers, synthetic polymers (e.g., branched and/or linear), non-emulsifiers, silica (e.g., nan-silica and/or colloidal silica), viscoelastic surfactants, and combinations thereof. In some embodiments, the biopolymers can include guar, xanthan, diutan, starch, cellulose, and/or derivatives thereof. In some embodiments, the functionalized biopolymers can include ethoxylated biopolymers, propoxylated biopolymers, methylated biopolymers, carboxymethylated biopolymers, or combinations thereof. For example, the functionalized biopolymers can include hydroxyethyl cellulose, hydroxypropyl guar, methylcellulose, carboxymethyl cellulose, carboxymethyl hydroxypropyl guar, or combinations thereof. In some embodiments, the synthetic polymers can include polyacrylamide polymers, acrylamide copolymers, 2-acylamido-2-methyl-1-propanesulfonic acid, polyvinylpyrrolidone, or combinations thereof. In some embodiments, the non-emulsifiers can include ethylene glycol monobutyl ether, decyl octyl glycosides, fatty acid derivative polymers, and/or combinations thereof. For example, the second aqueous solvent can include water treated with ethylene glycol monobutyl ether. Without being bound by theory, by injecting a second aqueous solvent after the injection of the organic solvent the oil recovery may increase due to the porous media allowing for aqueous fluid flow and sweeping of the carbonate layer 306b.

Now referring to FIG. 5, a method 400 of recovering oil is shown. At operation 510, data representing one or more physical characteristics of a subterranean formation is received by a computing workstation. In some embodiments, the data can be collected by one or more devices, e.g., measurement tools described herein, which are deployed in and/or near the subterranean formation. For example, the data can include a wireline tool 302c as described herein.

At operation 520, a first model of the subterranean formation is obtained. The first model can include the 3D geologic model 106, as described above. The first model represents rock properties as a function of location in the subterranean formation, as described herein. For example, the first model can represent the location of an oil-water contact location in the subterranean formation.

At operation 530, an oil phase proximal to an organic-aqueous phase based on the first model of the subterranean formation and the one or more physical characteristics. The oil phase comprises about 8 wt% to about 99 wt% asphaltene, e.g., about 10 wt% to about 99 wt%, about 20 wt% to about 99 wt%, about 30 wt% to about 99 wt%, about 40 wt% to about 99 wt%, about 50 wt% to about 99 wt%, about 60 wt% to about 99 wt%, about 70 wt% to about 99 wt%, about 80 wt% to about 99 wt%, or about 90 wt% to about 99 wt%. In some embodiments, the oil phase may proximal to the oil-water contact may include an oil phase located about 1 meters (m) to about 100 m to the oil-water contact, e.g., about 1 m to about 90 m, about 1 m to about 80 m, about 1 m to about 70 m, about 1 m to about 60 m, or about 1 m to about 50 m.

In some embodiments, identifying the oil-water contact includes generating a second model of the subterranean properties. The second model can represent fluid properties based on a location in the subterranean formation. For example, the second model can characterize asphaltene concentration based on the location in the subterranean formation. In some embodiments, the second model can include the fluid property model 114, as described above. Reservoir compartments of the subterranean formation can be identified based, at least partially, on the asphaltene concentration based on the location of the subterranean formation. For example, reservoir compartments including tar mats can be identified based on the asphaltene concentration in the location of the subterranean formation. In some embodiments, the reservoir compartments can include the reservoir simulation grid 110 as described herein. In some embodiments, the oil-water contact can be identified based on the reservoir compartments identified. For example, the oil-water contact can be identified by determining a first reservoir compart of the a carbonate layer 306b, and a second compartment of the aquipher layer 306e.

At operation 540, a tool is disposed at or above the oil-water contact of the subterranean formation. The tool can include an injector tool capable of injecting one or more solvents, e.g., aqueous solvents. In some embodiments, the tool can be fluidly coupled to an aqueous fluid line. The aqueous fluid line is fluidly coupled to a first aqueous solvent having a first viscosity of about 3x to about 6 x bigger than the aqueous phase of the aquipher layer 306e. The first aqueous solvent includes a surfactant, e.g., ethylene glycol monobutyl ether.

In some embodiments, the first aqueous solvent can include water. The water can be treated with one or more additives. In some embodiments, the one or more additives can include gelling agents, biopolymers, functionalized biopolymers, synthetic polymers (e.g., branched and/or linear), non-emulsifiers, silica (e.g., nan-silica and/or colloidal silica), viscoelastic surfactants, and combinations thereof. In some embodiments, the biopolymers can include guar, xanthan, diutan, starch, cellulose, and/or derivatives thereof. In some embodiments, the functionalized biopolymers can include ethoxylated biopolymers, propoxylated biopolymers, methylated biopolymers, carboxymethylated biopolymers, or combinations thereof. For example, the functionalized biopolymers can include hydroxyethyl cellulose, hydroxypropyl guar, methylcellulose, carboxymethyl cellulose, carboxymethyl hydroxypropyl guar, or combinations thereof. In some embodiments, the synthetic polymers can include polyacrylamide polymers, acrylamide copolymers, 2-acylamido-2-methyl-1-propanesulfonic acid, polyvinylpyrrolidone, or combinations thereof. In some embodiments, the non-emulsifiers can include decyl octyl glycosides, fatty acid derivative polymers, and/or combinations thereof.

At operation 550, the first aqueous solvent is injected into an aqueous phase that is proximal to the oil-water contact, e.g., the aquipher layer 306e, of the subterranean formation. The aqueous phase that is proximal to the oil-water contact includes a second viscosity of about 0.5 centipoise (cP) to about 1.5 cP. The first viscosity, e.g., the viscosity of the first aqueous solvent is greater than the second viscosity, e.g., the viscosity of the aqueous phase, e.g.,aquipher layer 306e, proximal to the oil-water contact. In some embodiments, the first viscosity may be about 1.1x to about 1000x greater than the second viscosity, e.g., about 1.1x to about 900x, about 2x to about 500x, about 4x to about 100x, or about 5x to about 10x. Without being bound by theory, a first aqueous solvent having a first viscosity that is greater than the second viscosity, e.g., the viscosity of the aqueous phase, e.g.,aquipher layer 306e, can allow for a viscous plug to form over the aquipher layer 306e, thereby preventing the aquipher layer from fingering into the oil phase, e.g., carbonate layer 306b, and increasing oil recovery from the well.

In some embodiments, the first aqueous solvent can be injected at a flow rate of about to about . In some embodiments, the first aqueous solvent can be injected at the oil-water contact and/or at a location that is about 1 m to about 10 m above the oil-water contact, e.g., about 1 m to about 9 m, about 1 m to about 7 m, or about 1 m to about 5 m.

In some embodiments, operating 550 can include injecting a second aqueous solvent fluidly coupled to the aqueous fluid line at the oil-water contact of the subterranean formation. The second aqueous solvent has a third viscosity that is less than the first viscosity. Without being bound by theory, injection of the second aqueous solvent at or above the oil-water contact can allow for efficient sweeping of oil recovery while avoiding diluting the first aqueous solvent and//or promoting fingering or coning of the aqueous phase, e.g., aquipher layer 306e. In some embodiments, the second aqueous solvent can be injected at a flow rate of about 100 barrels per day (bpd) to about 100000 bpd, e.g., about 100 bpd to about 10,000 bpd, about 1,000 bpd to about 10,000 bpd, or about 2,000 bpd to about 5,000 bpd. In some embodiments, the second aqueous solvent can be injected at or above the first aqueous solvent injection location.

In some embodiments, the second aqueous solvent can include water. The water can be treated with one or more additives. In some embodiments, the one or more additives can include gelling agents, biopolymers, functionalized biopolymers, synthetic polymers (e.g., branched and/or linear), non-emulsifiers, silica (e.g., nan-silica and/or colloidal silica), viscoelastic surfactants, and combinations thereof. In some embodiments, the biopolymers can include guar, xanthan, diutan, starch, cellulose, and/or derivatives thereof. In some embodiments, the functionalized biopolymers can include ethoxylated biopolymers, propoxylated biopolymers, methylated biopolymers, carboxymethylated biopolymers, or combinations thereof. For example, the functionalized biopolymers can include hydroxyethyl cellulose, hydroxypropyl guar, methylcellulose, carboxymethyl cellulose, carboxymethyl hydroxypropyl guar, or combinations thereof. In some embodiments, the synthetic polymers can include polyacrylamide polymers, acrylamide copolymers, 2-acylamido-2-methyl-1-propanesulfonic acid, polyvinylpyrrolidone, or combinations thereof. In some embodiments, the non-emulsifiers can include ethylene glycol monobutyl ether, decyl octyl glycosides, fatty acid derivative polymers, and/or combinations thereof. For example, the second aqueous solvent can include water treated with ethylene glycol monobutyl ether. Without being bound by theory, by injecting a second aqueous solvent after the injection of the first aqueous solvent, the oil recovery may increase due to sweeping of the carbonate layer 306b.

In some embodiments, operation 550 can include injecting an organic solvent at or above, e.g., proximal to the surface of the subterranean formation, the first aqueous solvent. In some embodiments, the organic solvent can be injected at a flow rate of about 100 barrels per day (bpd) to about 100000 bpd, e.g., about 100 bpd to about 10,000 bpd, about 1,000 bpd to about 10,000 bpd, or about 2,000 bpd to about 5,000 bpd . In some embodiments, the organic solvent can be injected at a pressure of greater than the formation pressure, in which the pressure does not exceed a pressure suitable to fracture the formation. Without being bound by theory, by injecting the organic solvent at or above, e.g., proximal to the surface of the subterranean formation, the first aqueous solvent, tight emulsions formed as a result of the first aqueous solvent and/or second aqueous solvent may be dispersed and/or degraded, thereby preventing clogging in the porous media during oil recovery.

Overall, the present disclosure can increase oil recovery efficiency by injecting an organic solvent from an organic fluid line into the oil phase to dissolve dissolved and/or dispersed asphaltenes in the subterranean formation, thereby reducing clogging of porous media used to recover the viscous oil. Moreover, the present disclosure can increase oil recovery efficiency by injecting an aqueous solvent having a greater viscosity than the aqueous phase, e.g., aquipher layer, at or above the oil-water contact, thereby preventing fingering and concurrently maintaining sweeping of the viscous oil in the reservoir. The present disclosure can also determine the location of the oil-water contact using one or more of modeling processes to ensure the location of the tool, e.g., aqueous injector and/or organic injector, is disposed at or slightly above the oil-water contact to provide efficient oil recovery.

The phrases, unless otherwise specified, "consists essentially of" and "consisting essentially of" do not exclude the presence of other steps, elements, or materials, whether or not, specifically mentioned in this specification, so long as such steps, elements, or materials, do not affect the basic and novel characteristics of the present disclosure, additionally, they do not exclude impurities and variances normally associated with the elements and materials used.

Numerical ranges used herein include the numbers recited in the range. For example, the numerical range “from 1 wt % to 10 wt %” includes 1 wt % and 10 wt % within the recited range.

For the sake of brevity, only some ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, within a range includes every point or individual value between its end points even though not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.

All numerical values within the detailed description herein are modified by “about” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.

All documents described herein are incorporated by reference herein, including any priority documents and or testing procedures to the extent they are not inconsistent with this text. As is apparent from the foregoing general description and the specific embodiments, while forms of the present disclosure have been illustrated and described, various modifications can be made without departing from the spirit and scope of the present disclosure. Accordingly, it is not intended that the present disclosure be limited thereby. Likewise, the term “comprising” is considered synonymous with the term “including” for purposes of United States law. Likewise whenever a composition, an element or a group of elements is preceded with the transitional phrase “comprising,” it is understood that we also contemplate the same composition or group of elements with transitional phrases “consisting essentially of,” “consisting of,” “selected from the group of consisting of,” or “is” preceding the recitation of the composition, element, or elements and vice versa.

The specific embodiments described herein have been illustrated by way of example, and it should be understood that these embodiments may be susceptible to various modifications and alternative forms. It should be further understood that the claims are not intended to be limited to the particular forms disclosed, but rather to cover all modifications, equivalents, and alternatives falling within the spirit and scope of this disclosure.

The techniques presented and claimed herein are referenced and applied to material objects and concrete examples of a practical nature that demonstrably improve the present technical field and, as such, are not abstract, intangible or purely theoretical. Further, if any claims appended to the end of this specification contain one or more elements designated as “means for (perform)ing (a function)…” or “step for (perform)ing (a function)…”, it is intended that such elements are to be interpreted under 35 U.S.C. 112(f). However, for any claims containing elements designated in any other manner, it is intended that such elements are not to be interpreted under 35 U.S.C. 112(f).

Embodiments

Implementation examples are described in the following numbered clauses:

E1. A method for oil recovery, the method comprising receiving data representing one or more physical characteristics of a subterranean formation, wherein the data is collected by one or more devices deployed in or near the subterranean formation; obtaining a first model of the subterranean formation, the first model representing rock properties as a function of location in the subterranean formation; identifying an oil phase proximal to an oil-water contact based on the first model of the subterranean formation and the one or more physical characteristics, the oil phase comprising about 8 wt% to about 99 wt% asphaltene; disposing a tool in the oil phase proximal to the oil-water contact of the subterranean formation, the tool fluidly coupled to an aqueous fluid line and an organic fluid line; injecting a first aqueous solvent from the aqueous fluid line into the oil phase; and injecting an organic solvent from the organic fluid line into the oil phase.

E2. The method of embodiment E1, further comprising injecting a second aqueous solvent from the aqueous fluid line.

E3. The method of embodiments E1 or E2, wherein identifying the oil-water contact further comprises generating a second model of the subterranean formation, the second model representing fluid properties based on a location in the subterranean formation, wherein the fluid properties of the second model characterize asphaltene concentration based on the location in the subterranean formation; identifying reservoir compartments of the subterranean formation based at least partially on the asphaltene concentration based on the location in the subterranean formation; and identifying the oil-water contact based on the reservoir compartments.

E4. The method of embodiment E3, wherein the reservoir compartments comprise a tar mat.

E5. The method of embodiments E1 or E2, wherein the first aqueous solvent and the second aqueous solvent comprise water.

E6. The method of embodiment E5, wherein the water is treated with a non-emulsifier comprising one or more of ethylene glycol monobutyl ether, decyl octyl glycosides, fatty acid derivative polymers, or combinations thereof.

E7. The method of any one of embodiments E1-E6, wherein the organic solvent comprises one or more of xylene, maleic acid dicarboxylic ester, adipic acid dicarboxylic acid, succinic ester, acetic ester, formic ester, or combinations thereof.

E8. A method for oil recovery, the method comprising receiving data representing one or more physical characteristics of a subterranean formation, wherein the data is collected by one or more devices deployed in or near the subterranean formation; obtaining a first model of the subterranean formation, the first model representing rock properties as a function of location in the subterranean formation; identifying an oil phase proximal to an oil-water contact based on the first model of the subterranean formation and the one or more physical characteristics, the oil phase disposed above the oil-water contact; disposing a tool at or above the oil-water contact, the tool fluidly coupled to an aqueous fluid line; and injecting a first aqueous solvent, having a first viscosity, from the aqueous fluid line into an aqueous phase proximal to the oil-water contact, the aqueous phase proximal to the oil-water contact comprising a second viscosity, wherein the first aqueous solvent comprises a surfactant, and wherein the first viscosity is greater than the second viscosity.

E9. The method of embodiment E8, wherein identifying the oil-water contact further comprises generating a second model of the subterranean formation, the second model representing fluid properties based on a location in the subterranean formation, wherein the fluid properties of the second model characterize asphaltene concentration based on the location in the subterranean formation; identifying reservoir compartments of the subterranean formation based at least partially on the asphaltene concentration based on the location in the subterranean formation; and identifying the oil-water contact based on the reservoir compartments.

E10. The method of embodiment E8 or E9, wherein the reservoir compartments comprise a tar mat.

E11. The method of any one of embodiments E8-E10, wherein the first aqueous solvent comprises water.

E12. The method of embodiment E11, wherein the water is treated with a non-emulsifier comprising one or more of decyl octyl glycosides, fatty acid derivative polymers, or combinations thereof.

E13. The method of any one of embodiments E8-E12, wherein the surfactant comprises ethylene glycol monobutyl ether.

E14. The method of any one of embodiments E8-E13, further comprising injecting a second aqueous solvent, the second aqueous solvent comprising a third viscosity.

E15. A method for oil recovery, the method comprising receiving data representing one or more physical characteristics of a subterranean formation, wherein the data is collected by one or more devices deployed in or near the subterranean formation; obtaining a first model of the subterranean formation, the first model representing rock properties as a function of location in the subterranean formation; identifying an oil phase proximal to an oil-water contact based on the first model of the subterranean formation and the one or more physical characteristics, the oil phase comprising about 8 wt% to about 99 wt% asphaltene; and disposing a tool in the oil phase proximal to the oil-water contact of the subterranean formation, the tool fluidly coupled to an aqueous fluid line and an organic fluid line; injecting a first aqueous solvent, having a first viscosity, from the aqueous fluid line into an aqueous phase proximal to the oil-water contact, the aqueous phase proximal to the oil-water contact comprising a second viscosity, wherein the first aqueous solvent comprises a surfactant, and wherein the first viscosity is greater than the second viscosity the first aqueous solvent comprising a surfactant; and injecting an organic solvent from the organic fluid line above the first aqueous solvent.

E16. The method of embodiment E15, wherein identifying the oil-water contact further comprises generating a second model of the subterranean formation, the second model representing fluid properties based on a location in the subterranean formation, wherein the fluid properties of the second model characterize asphaltene concentration based on the location in the subterranean formation; identifying reservoir compartments of the subterranean formation based at least partially on the asphaltene concentration based on the location in the subterranean formation; and identifying the oil-water contact based on the reservoir compartments.

E17. The method of embodiment E15 or E16, wherein the first aqueous solvent comprises water treated with a non-emulsifier comprising one or more of decyl octyl glycosides, fatty acid derivative polymers, or combinations thereof.

E18. The method of embodiment E17, wherein the organic solvent comprises one or more of xylene, maleic acid dicarboxylic ester, adipic acid dicarboxylic acid, succinic ester, acetic ester, or formic ester.

E19. The method of any one of embodiments E15-E18, wherein the surfactant comprises ethylene glycol monobutyl ether.

E20. The method of any one of embodiments E15-E19, further comprising injecting a second aqueous solvent, the second aqueous solvent comprising a third viscosity.

While the present disclosure has been described with respect to a number of embodiments and examples, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope and spirit of the present disclosure.