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WO2020214167A1 - Extrapolation de données de laboratoire afin de réaliser des prédictions de performances d'échelle de réservoir - Google Patents

Extrapolation de données de laboratoire afin de réaliser des prédictions de performances d'échelle de réservoir Download PDF

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Publication number
WO2020214167A1
WO2020214167A1 PCT/US2019/027977 US2019027977W WO2020214167A1 WO 2020214167 A1 WO2020214167 A1 WO 2020214167A1 US 2019027977 W US2019027977 W US 2019027977W WO 2020214167 A1 WO2020214167 A1 WO 2020214167A1
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Prior art keywords
liquid reservoir
surfactant
unconventional
scaling group
unconventional liquid
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Inventor
Liang Xin XU
David Schechter
Antonio Recio
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Multi Chem Group LLC
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Multi Chem Group LLC
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Priority to PCT/US2019/027977 priority Critical patent/WO2020214167A1/fr
Priority to ARP200100651A priority patent/AR118303A1/es
Publication of WO2020214167A1 publication Critical patent/WO2020214167A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
    • E21B2200/20—Computer models or simulations, e.g. for reservoirs under production, drill bits

Definitions

  • Fracturing treatments are commonly used in subterranean operations, among other purposes, to stimulate the production of desired fluids (e.g., oil, gas, water, etc.) from a subterranean formation.
  • hydraulic fracturing treatments generally involve pumping a treatment fluid (e.g., a fracturing fluid) into a well bore that penetrates a subterranean formation at a sufficient hydraulic pressure to create or enhance one or more fractures in the subterranean formation.
  • the creation and/or enhancement of these fractures may enhance the production of fluids from the subterranean formation.
  • EOR enhanced oil recovery
  • small hydrocarbon gasses such as methane, ethane, and propane may be injected into a well to increase mobility of hydrocarbons trapped in the subterranean formation.
  • Surfactants may be injected alongside the hydrocarbons to modify the subterranean formation faces to impart hydrophobic or hydrophilic properties. Surfactants may aid in production of oil and gas by allowing water and hydrocarbons to flow with less resistance by disrupting the boundary layer created between water and oil.
  • Figure 1 is a schematic view of an example of a well environment utilized for hydraulic fracturing
  • Figure 2 is a schematic view of an example of a wellbore after the introduction of fracturing fluid
  • Figure 3 illustrates a flowchart for identifying a surfactant to use in an unconventional liquid reservoir (ULR) from a scaling group;
  • ULR unconventional liquid reservoir
  • Figure 4 illustrates an example of a laboratory setup to test surfactants on core samples
  • Figure 5A illustrates an example of conventional Equation 1 for an underground formation
  • Figure 5B illustrates an example of conventional Equation 2 for an underground formation
  • Figure 5C illustrates an example of unconventional Equation 3 for an underground formation
  • Figure 5D illustrates an example of an unconventional Equation 4 for an underground formation
  • Figure 6A illustrates an example of unconventional Equation 3 for an underground formation
  • Figure 6B illustrates an example of unconventional Equation 4 for an underground formation
  • Figure 6C illustrates an example of unconventional Equation 3 for an underground formation
  • Figure 6D illustrates an example of unconventional Equation 4 for an underground formation.
  • the systems, methods, and/or compositions disclosed herein may relate to subterranean operations and, in some systems and methods for determining how a surfactant may operate in an underground formation.
  • techniques such as enhanced oil recovery (EOR) may be used. Such techniques may be especially useful in shale formations, as the rate of recovery of liquid hydrocarbons may be lower compared to other types of formations.
  • a shale formation may have extremely low permeability typically on the order of about 1 O 4 to about 1 O 10 millidarcy (mD) which may present challenges to flow of oil and gas.
  • Hydraulic fracturing may increase the permeability of the subterranean formation by breaking apart the formation and creating fractures and flow paths for hydrocarbons. During fracturing, surfactants may be used to further increase the production capability of the formation.
  • Figure 1 illustrates an example of a well environment 104 that may be used to introduce surfactant into fractures 100.
  • Well environment 104 may include a fluid handling system 106, which may include fluid supply 108, mixing equipment 109, pumping equipment 110, and wellbore supply conduit 112.
  • Pumping equipment 110 may be fluidly coupled with the fluid supply 108 and wellbore supply conduit 112 to communicate a fracturing fluid 117, which may comprise surfactant into wellbore 114.
  • Fluid supply 108 and pumping equipment 1 10 may be above the surface 1 18 while wellbore 1 14 is below surface 1 18.
  • Well environment 104 may also be used for the injection of a pad or pre-pad fluid into the subterranean formation at an injection rate at or above the fracture gradient to create at least one fracture 100 in subterranean formation 120.
  • Well environment 104 may then inject fracturing fluid 117 into subterranean formation 120 surrounding wellbore 1 14.
  • a wellbore 114 may include horizontal, vertical, slanted, curved, and other types of wellbore geometries and orientations, and surfactant may generally be applied to subterranean formation 120 surrounding any portion of wellbore 114, including fractures 100.
  • Wellbore 114 may include casing 102 that may be cemented (or otherwise secured) to the wall of wellbore 114 by cement sheath 122.
  • Perforations 123 may allow' communication between wellbore 114 and subterranean formation 120. As illustrated, perforations 123 may penetrate casing 102 and cement sheath 122 allowing communication between interior of casing 102 and fractures 100.
  • a plug 12.4, winch may be any type of plug for oilfield applications (e.g., bridge plug), may be disposed in wellbore 114 below' perforations 123.
  • a perforated interval of interest 130 may be isolated with plug 124.
  • a pad or pre-pad fluid may be injected into subterranean formation 120 at an injection rate at or above the fracture gradient to create at least one fracture 100 in subterranean formation 120.
  • proppant may be mixed with an aqueous based fluid via mixing equipment 109, thereby forming a fracturing fluid 117, and then may be pumped via pumping equipment 110 from fluid supply 108 down the interior of casing 102 and into subterranean formation 120 at or above a fracture gradient of subterranean formation 120.
  • Pumping the fracturing fluid 117 at or above the fracture gradient of the subsurface formation 120 may create (or enhance) at least one fracture (e.g., fractures 100) extending from the perforations 123 into the subterranean formation 120.
  • fracturing fluid 117 may be pumped down production tubing, coiled tubing, or a combination of coiled tubing and annulus between the coiled tubing and casing 102.
  • At least a portion of fracturing fluid 117 may enter fractures 100 of subterranean formation 120 surrounding wellbore 114 by way of perforations 123.
  • Perforations 123 may extend from the interior of casing 102, through cement sheath 122, and into subterranean formation 120.
  • wellbore 114 is shown after placement of surfactant in accordance with systems and/or methods of the present disclosure.
  • Surfactant may be positioned within fractures 100, thereby propping open fractures 100.
  • Pumping equipment 110 may include a high pressure pump.
  • the term“high pressure pump” refers to a pump that is capable of delivering fracturing fluid 117 and/or pad/pre pad fluid downhole at a pressure of about 1000 psi or greater.
  • a high pressure pump may be used when it is desired to introduce fracturing fluid 117 and/or pad/pre-pad fluid into subterranean formation 120 at or above a fracture gradient of subterranean formation 120, but it may also be used in cases where fracturing is not desired.
  • the high pressure pump may be capable of fluidly conveying particulate matter, such as proppant, into subterranean formation 120.
  • Suitable high pressure pumps may include, but are not limited to, floating piston pumps and positive displacement pumps.
  • the initial pumping rates of the pad fluid, pre pad fluid and/or fracturing fluid 117 may range from about 15 barrels per minute (“bbl/min”) to about 80 bbl/min, enough to effectively create a fracture into the formation and place proppant at least one fracture 101.
  • pumping equipment 110 may include a low pressure pump.
  • the term“low pressure pump” refers to a pump that operates at a pressure of about 1000 psi or less.
  • a low pressure pump may be fluidly coupled to a high pressure pump that may be fluidly coupled to a tubular (e.g., wellbore supply conduit 112).
  • the low pressure pump may be configured to convey fracturing fluid 117 and/or pad/pre-pad fluid to the high pressure pump.
  • the low pressure pump may“step up” the pressure of fracturing fluid 117 and/or pad/pre-pad fluid before it reaches the high pressure pump.
  • Mixing equipment 109 may include a mixing tank that is upstream of pumping equipment 110 and in which fracturing fluid 117 may be formulated.
  • Pumping equipment 110 e.g., a low pressure pump, a high pressure pump, or a combination thereol
  • fracturing fluid 117 may be formulated offsite and transported to a worksite, in which case fracturing fluid 117 may be introduced to casing 102 via pumping equipment 110 directly from its shipping container (e.g., a truck, a railcar, a barge, or the like) or from a transport pipeline.
  • fracturing fluid 117 may be drawn into pumping equipment 110, elevated to an appropriate pressure, and then introduced into casing 102 for delivery downhole.
  • Exemplary fracturing fluid 117 disclosed herein may directly or indirectly affect one or more components or pieces of equipment associated with the preparation, delivery, recapture, recycling, reuse, and/or disposal of the fracturing fluid.
  • fracturing fluid 117 may directly or indirectly affect one or more mixers, related mixing equipment, mud pits, storage facilities or units, composition separators, heat exchangers, sensors, gauges, pumps, compressors, and the like used generate, store, monitor, regulate, and/or recondition the sealant composition.
  • Fracturing fluid 117 may also directly or indirectly affect any transport or delivery equipment used to convey fracturing fluid 117 to a well site or downhole such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to compositionally move fracturing fluid 117 from one location to another, any pumps, compressors, or motors (e.g., topside or downhole) used to drive fracturing fluid 117 into motion, any valves or related joints used to regulate the pressure or flow rate of the fracturing fluid, and any sensors (i.e., pressure and temperature), gauges, and/or combinations thereof, and the like.
  • any transport or delivery equipment used to convey fracturing fluid 117 to a well site or downhole such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to compositionally move fracturing fluid 117 from one location to another, any pumps, compressors, or motors (e.g., topside or downhole) used to drive
  • the disclosed fracturing fluid 117 may also directly or indirectly affect the various downhole equipment and tools that may come into contact with fracturing fluid 117 such as, but not limited to, wellbore casing, wellbore liner, completion string, insert strings, drill string, coiled tubing, slickline, wireline, drill pipe, drill collars, mud motors, downhole motors and/or pumps, cement pumps, surface-mounted motors and/or pumps, centralizers, turbolizers, scratchers, floats (e.g., shoes, collars, valves, etc.), logging tools and related telemetry equipment, actuators (e.g., electromechanical devices, hydromechanical devices, etc.), sliding sleeves, production sleeves, plugs, screens, filters, flow control devices (e.g., inflow control devices, autonomous inflow control devices, outflow control devices, etc.), couplings (e.g., electro-hydraulic wet connect, dry connect, inductive coupler, etc.), control lines (e.g., electrical, fiber optic
  • Imbibition refers to the absorption of a wetting phase into porous rock. Imbibition may be an important factor in the ability of hydrocarbons to move through the reservoir, as imbibition may promote or hinder hydrocarbon movement in subterranean formation 120 (e.g., Referring to Figure 1). If hydrocarbons are strongly imbibed into a rock, the hydrocarbons may be less likely to flow through subterranean formation 120 to a wellbore 114. If the opposite is true where a rock strongly imbibes water, hydrocarbons may more easily flow. Some rocks may imbibe both water and oil, with water imbibing at low in-situ water saturation, thereby displacing oil from the surface of the rock grains. The same rock may be oil imbibing at low in situ oil saturation thereby displacing excess water. In general, improving the water imbibition properties of a rock may increase hydrocarbon production by absorbing excess water into the rock and allowing oil to flow freer.
  • Water-wet and oil-wet may refer to the preference of a solid to be in contact with a water- rich phase or an oil-rich phase respectively.
  • a coating of oil may cover the surface of solid or rock.
  • Oil-wet rocks may preferentially imbibe oil.
  • Some wellbore conditions may increase the oil-wetness of a rock such as polar compounds and asphaltene deposits onto mineral surfaces.
  • Other conditions such as exposure to oil-based drilling mud may also create an oil-wet condition.
  • rocks In a water-wet condition, rocks may be covered in water and may preferentially imbibe water. Water-wet conditions are desirable for efficient hydrocarbon transport. Wettability may be a function of surface forces and interfacial forces.
  • water imbibition treatments may be performed from an injector well where a fluid containing a surfactant that promotes water imbibition is injected.
  • the injected fluid “sweeps” the hydrocarbons in subterranean formation 120 to a production well.
  • surfactants such as anionic surfactants, non-ionic surfactants, and nanoparticle surfactants have been used as wettability modifiers in such applications.
  • These treatments suffer drawbacks such as short timeframes for wettability modification.
  • Surfactants may be loosely bound to the formation rocks and are easily displaced and produced alongside hydrocarbons leading to a need to introduce surfactants to keep production up continually. Therefore, a laboratory means of identifying surfactants to use in subterranean formation 120 may be beneficial.
  • FIG. 3 illustrates a flow chart 300 for identifying a surfactant to use in an unconventional liquid reservoir from a scaling group.
  • flowchart 300 may begin with step 302, obtaining a core sample from an unconventional liquid reservoir.
  • an operator may utilize a coring drill to drill into subterranean formation 120 (e.g., referring to Figure 1), where subterranean formation 120 may be an unconventional liquid reservoir.
  • samples from subterranean formation 120 may be removed to surface 118 (e.g., referring to Figure 1). These samples may be sent to a laboratory for testing before production and/or completion operations may begin on subterranean formation 120.
  • Step 304 may include testing core samples for spontaneous imbibition data.
  • Figure 4 illustrates lab setup 400 for evaluating the performance of hydraulic fracturing fluid additives, surfactants , to extract oil and gas from hydrocarbon laden reservoirs, spontaneous imbibition lab tests on small reservoir core samples 402. Without being bound by any theory, it may be believed that such a method may be used for predicting oil recovery from large reservoir matrix blocks, particularly when preserved rock samples are used and the properties of the lab system are almost the same as those of the field. However, despite having lab results that demonstrate the effectiveness of various fracturing fluid additives, surfactants , it has been difficult to tie the observed performance in a laboratory seting to actual performance of a reservoir.
  • the various dimensions of rock may determine actual oil and gas recovery rate and factor and therefore a universal scaling group may be utilized to scale up the oil recovery results.
  • Determining imbibition data in step 304 may be useful in improving the recovery of fluids from subterranean formation 120 (e.g., referring to Figure 1) during oil recovery operations.
  • oil recover may be driven by multistage hydraulic fracturing technology, which may be utilized in ultralow permeability formations that characterizes an unconventional liquid reservoir. Fracture networks generated from the multistage hydraulic fracturing completions interacting with naturally occurring fractures provides crucial flow paths for liquids to flow from the unconventional liquid reservoir. Laboratory studies, such as the one described above, have shown that in comparison to the base case of water without surfactant, the presence of surfactant increases both the rate of production and ultimate recovery of oil from an unconventional liquid reservoir. With numerous variables determining the efficacy of a multistage hydraulic fracturing treatment, optimization of surface active agents (molecular type, volume, concentration... etc.) may allow an operator to improve performance in old and new wells across vast acreage characteristic of these resource plays.
  • surfactant molecules may act as a bridge between the two immiscible phases present in the pore system, oil and water, with the two segments of the molecule, known as head and tail, possess different affinity to the aqueous and oleic phases.
  • the head of the surfactant molecule is hydrophilic, having a higher affinity towards the aqueous phase, and the tail portion of the surfactant molecule which is hydrophobic, thus having a higher affinity towards crude oil molecule. Partitioning of the head group in the aqueous phase and the tail group in the oleic phase primarily results in lowering of the oil-water interfacial tension.
  • Interfacial tension of oil and water may be an essential variable in the surfactant-assisted spontaneous imbibition, acting as the driving force once wettability may be altered.
  • a pendant drop method may be used to measure the interfacial tension due to the accuracy of this method in the range of an interaction tension value encountered with the surfactants used, for example, a value range between about 0.1 mN/m to about 30 mN/m.
  • the measurement of the contact angle may be the preferential method to determine the wetability of the rock. Since injection into the core from resource plays is not possible, saturation, re-saturation and classic techniques such as the Amott or USBM techniques may not be feasible. Thus, static contact angle on reservoir surfaces aged in crude oil has been extensively reported as the quantitative determination of wetability.
  • step 306 may implement a scaling group that correlates to the imbibition data, which was determined in step 304.
  • scaling models for conventional high permeability core samples may be used in known techniques, but scaling models for unconventional reservoirs are new and inventive concepts not previously utilized in known scaling techniques.
  • Scaling groups that were designed for use on conventional high permeability rock may not be applicable to ultralow permeability shale reservoirs. The scaling groups are shown below:
  • Eq. (1) the scaling model presented in Eq. (1) does not consider the wetability effect without the presence of contact angle.
  • the contact angle represents wetability of the rock surface, where wetability alteration and moderate interfacial tension reduction improve oil recovery in unconventional liquid reservoirs. Wetability may be the focus in a scaling group analysis.
  • Eq. (2) may be utilized as the scaling model to analyze spontaneous imbibition and upscale the laboratory data to the field.
  • Upscaling surfactant-assisted spontaneous imbibition laboratory results to the field may be performed through an analytical method to scale experimental laboratory data.
  • Analytical methods may assume dimensionless time at which half of the oil has been produced in the rock has the same value in the lab experiments as in the field.
  • methods described above may include dimensionless time as a variable that is equal to lab scale and field scale.
  • spontaneous imbibition experimental data a field production rate may be predicted analytically.
  • a dual porosity simulation model and a DFN model are also developed in order to upscale the laboratory results to the field.
  • DFN discrete fracture network
  • DFN represents the high-permeability paths generated when the hydraulic fracture may interact with a natural fracture that may be present pervasively in the reservoir rock of subterranean formation 120 (e.g., referring to Figure 1).
  • the unstructured mesh utilized could accurately capture the complex fracture geometry with low computation cost, compared to a structured grid.
  • the complexity of a DFN such as extensive fracture clustering, non-orthogonal, and low-angle fracture intersections may be handled, thus vastly improving the sugar cube model that may utilize empirical transfer functions in dual-porosity reservoirs.
  • Another advantage of this explicit approach is to minimize the grid orientation effect inside fractures and distribute the aperture of fractures as observed in naturally occurring fractures.
  • methods may upscale laboratory results to the field, by evaluating the effectiveness of surfactant to completion fluid in enhancing oil recovery in unconventional liquid reservoirs.
  • contact angle (“CA”) and IFT measurements may be performed to study the capability of surfactants in wettability alteration and IFT reduction.
  • spontaneous imbibition experiments may be conducted to analyze the impact of surfactants on ultimate oil recovery along with time-lapse CT scan technology in order to visualize water penetration into the core and to generate the core porosity model for history match simulation of spontaneous imbibition.
  • capillary pressure and relative permeability curves of unconventional liquid reservoir core samples may be obtained by scaling group analysis and history matching spontaneous imbibition results, respectively.
  • laboratory results may be upscaled by scaling group analysis, dual porosity models, and DFN models to estimate field production and compare the upscaling results by all three methods.
  • modeling, upscaling, and estimating field production may be, at least in part, implemented with an information handling system (not illustrated).
  • Information handling system may include any instrumentality or aggregate of instrumentalities operable to compute, estimate, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes.
  • an information handling system may be a processing unit, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price.
  • Information handling system may include random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or hardware or software control logic, ROM, and/or other types of nonvolatile memory. Additional components of the information handling system may include one or more disk drives, one or more network ports for communication with external devices as well as an input device (e.g., keyboard, mouse, etc.) and video display. Information handling system may also include one or more buses operable to transmit communications between the various hardware components.
  • RAM random access memory
  • processing resources such as a central processing unit (CPU) or hardware or software control logic, ROM, and/or other types of nonvolatile memory.
  • Additional components of the information handling system may include one or more disk drives, one or more network ports for communication with external devices as well as an input device (e.g., keyboard, mouse, etc.) and video display.
  • Information handling system may also include one or more buses operable to transmit communications between the various hardware components.
  • Non-transitory computer-readable media 122 may include any instrumentality or aggregation of instrumentalities that may retain data and/or instructions for a period of time.
  • Non-transitory computer-readable media may include, for example, storage media such as a direct access storage device (e.g., a hard disk drive or floppy disk drive), a sequential access storage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory; as well as communications media such wires, optical fibers, microwaves, radio waves, and other electromagnetic and/or optical carriers; and/or any combination of the foregoing.
  • non-transitory computer-readable media may store a program. The program may be activated to for modeling, upscaling, estimating field production, and/or the like.
  • Figures 5A-5D depict a comparison of the data obtained from the conventional and unconventional scaling groups.
  • Figures 5A and 5B show that the conventional scaling groups (i.e., Equations 1 and 2) results in more than an order of magnitude shift in dimensionless time for both anionic and nonionic/cationic surfactants.
  • Figures 5C and 5D show that the unconventional scaling groups (i.e., Equations 3 and 4) appear to compensate for that difference as realized by the fact that all of the curves now begin to fall within the same order of magnitude.
  • the unconventional scaling groups (i.e., Equations 3 and 4) revealed in this disclosure may be used to compare the performance of fracturing fluids 117 comprising surfactants (e.g., Referring to Figure 1) in various shale reservoirs.
  • surfactants e.g., Referring to Figure 1
  • the slope of the best fit line of the numerous data points may be considered a quantification of oil recovery rate.
  • Figures 6A-6D suggests that fracturing fluids 117 containing additives of surfactant tend to perform better in identified shale plays.
  • step 308 may identify a surfactant based at least in part on the scaling group for an unconventional liquid reservoir.
  • the unconventional scaling models may be used to compare individual fracturing fluids 117 with different fracturing additives such as surfactant , scale inhibitor, biocide, etc. From the unconventional scaling models capillary pressure and relative permeability changes over water or oil saturation may be extracted, which may be utilized to optimize chemical formulations such as modifying functional groups on the backbone of molecules.
  • Step 310 includes adding the chosen surfactant to the unconventional liquid reservoir. Adding a surfactant to an unconventional liquid reservoir may improve the efficiency at which formation fluids may be removed from an unconventional liquid reservoir.
  • This method and system may include any of the various features of the compositions, methods, and system disclosed herein, including one or more of the following statements.
  • a method for identifying a surfactant to use in an unconventional liquid reservoir may comprise testing a core sample for spontaneous imbibition data, identifying a scaling group that correlates to the spontaneous imbibition data, identifying at least one surfactant based at least in part on the scaling group for use in the unconventional liquid reservoir, and injecting the at least one surfactant into the unconventional liquid reservoir.
  • Statement 2 The method of statement 1, wherein the injecting the at least one surfactant comprising injecting a fracturing fluid comprising the at least one surfactant into the unconventional liquid reservoir.
  • t is actual time of imbibition
  • k is permeability
  • f porosity
  • mn water viscosity
  • L c is characteristic length factor
  • s is interfacial tension
  • m 0 oil viscosity
  • Statement 5 The method of statements 1 to 4, further comprising obtaining a core sample from the unconventional liquid reservoir.
  • Statement 6 The method of statements 1 to 5, further comprising perforating the unconventional liquid reservoir.
  • Statement 7 The method of statements 1 to 6, further comprising injecting a fracturing fluid into the unconventional liquid reservoir.
  • Statement 8 The method of statements 1 to 7, further comprising comparing individual fracturing fluids with at least the scaling group and wherein the individual fracturing fluids comprise at least one additive selected from the group consisting of a surfactant, a scale inhibitor, and a biocide.
  • Statement 9 The method of statements 1 to 8, further comprising removing a formation fluid from the unconventional liquid reservoir.
  • a method for identifying a surfactant to use in an unconventional liquid reservoir may comprise obtaining a core sample from the unconventional liquid reservoir, testing a core sample for spontaneous imbibition data, implementing a scaling group that correlates to the spontaneous imbibition data, wherein the scaling group is defined a s t D - t abs(l0 ⁇ f _l 0S(e)) T x f 2 .
  • t is actual time of imbibition
  • k is permeability
  • f porosity
  • m in water viscosity
  • L c is characteristic length factor
  • s is interfacial tension
  • m 0 is oil viscosity
  • Statement 11 The method of statement 10, further comprising perforating the unconventional liquid reservoir and comprising injecting a fracturing fluid into the unconventional liquid reservoir.
  • Statement 12 The method of statements 10 or 11, further comprising comparing individual fracturing fluids with at least the scaling group.
  • Statement 13 The method of statements 10 to 12, further comprising removing a formation fluid from the unconventional liquid reservoir.
  • a method for identifying a surfactant to use in an unconventional liquid reservoir may comprise testing a core sample for spontaneous imbibition data, implementing a scaling group that correlates to the spontaneous imbibition data, wherein the scaling group is f abs(log ⁇ ) cos(0))
  • t D t , wherein t is actual time of imbibition, k is permeability, f is
  • mn water viscosity
  • L c characteristic length factor
  • s interfacial tension
  • m 0 oil viscosity
  • Statement 15 The method of statement 14, further comprising perforating the unconventional liquid reservoir and injecting a fracturing fluid into the unconventional liquid reservoir.
  • Statement 16 The method of statements 14 or 15, further comprising comparing individual fracturing fluids with at least the scaling group.
  • Statement 17 The method of statements 14 to 16, further comprising removing a formation fluid from the unconventional liquid reservoir.
  • a system for identifying a surfactant to use in an unconventional liquid reservoir may comprise a processing unit and a non-transitory computer-readable media coupled to the processing unit.
  • the non-transitory computer-readable media stores a program configured to simulate a well system, implement a scaling group that correlates to imbibition data, and identify at least one surfactant based at least in part on the scaling group for use in the unconventional liquid reservoir.
  • t is actual time of imbibition
  • k is permeability
  • f porosity
  • m n water viscosity
  • L c is characteristic length factor
  • s is interfacial tension
  • m 0 oil viscosity
  • 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.
  • any numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed.
  • every range of values (of the form,“from about a to about b,” or, equivalently,“from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited.
  • 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.

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  • Lubricants (AREA)

Abstract

La présente invention concerne un procédé et un système permettant d'identifier un tensioactif à utiliser dans un réservoir de liquide non conventionnel. Le procédé peut consister à tester un échantillon de carotte pour des données d'imbibition spontanée, à identifier un groupe de mise à l'échelle qui est en corrélation avec les données d'imbibition spontanée, à identifier au moins un tensioactif sur la base, au moins en partie, du groupe de mise à l'échelle destiné à être utilisé dans le réservoir de liquide non conventionnel, et à injecter le ou les tensioactifs dans le réservoir de liquide non conventionnel. Le système peut comprendre une unité de traitement et un support non transitoire lisible par ordinateur couplé à l'unité de traitement, le support non transitoire lisible par ordinateur stockant un programme. Le programme peut être configuré pour simuler un système de puits et mettre en œuvre un groupe de mise à l'échelle qui est en corrélation avec des données d'imbibition. Le système peut en outre comprendre l'identification d'au moins un tensioactif sur la base, au moins en partie, du groupe de mise à l'échelle destiné à être utilisé dans le réservoir de liquide non conventionnel.
PCT/US2019/027977 2019-04-17 2019-04-17 Extrapolation de données de laboratoire afin de réaliser des prédictions de performances d'échelle de réservoir Ceased WO2020214167A1 (fr)

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PCT/US2019/027977 WO2020214167A1 (fr) 2019-04-17 2019-04-17 Extrapolation de données de laboratoire afin de réaliser des prédictions de performances d'échelle de réservoir
ARP200100651A AR118303A1 (es) 2019-04-17 2020-03-10 Extrapolación de datos de laboratorio para realizar predicciones del rendimiento del yacimiento a escala

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CN113187458A (zh) * 2021-05-31 2021-07-30 新疆正通石油天然气股份有限公司 一种利用压裂前置液将驱油剂注入油层提高采收率的方法
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CN115749758A (zh) * 2022-11-14 2023-03-07 常州大学 一种关于稠油开采实时监测含油饱和度实验装置及方法

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CN112855108A (zh) * 2021-03-18 2021-05-28 中国地质大学（北京） 致密储层滑溜水压裂液渗吸采收率预测方法以及预测装置
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CN115142827A (zh) * 2021-03-29 2022-10-04 中国石油化工股份有限公司 压裂工艺的确定方法、装置、设备及存储介质
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CN113187458A (zh) * 2021-05-31 2021-07-30 新疆正通石油天然气股份有限公司 一种利用压裂前置液将驱油剂注入油层提高采收率的方法
CN113187458B (zh) * 2021-05-31 2023-05-12 新疆正通石油天然气股份有限公司 一种利用压裂前置液将驱油剂注入油层提高采收率的方法
CN113295580A (zh) * 2021-06-10 2021-08-24 西安石油大学 一种综合动静态渗吸提高致密砂岩采收率的方法及系统
CN113295580B (zh) * 2021-06-10 2023-10-24 西安石油大学 一种综合动静态渗吸提高致密砂岩采收率的方法及系统
CN115749758A (zh) * 2022-11-14 2023-03-07 常州大学 一种关于稠油开采实时监测含油饱和度实验装置及方法
CN115749758B (zh) * 2022-11-14 2023-08-08 常州大学 一种关于稠油开采实时监测含油饱和度实验装置及方法

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