Saudi Arabian Oil Company

Case Western Reserve University

Aramco Services Company

Hui-Hai Liu

Jilin Jay Zhang

Daniel T Georgi

Jinhong Chen

Bitao Lai

Huangye Chen

Stacey Marie Althaus

Yanhui Han

Jewel Duncan

Lorne Arthur Davis, Jr

Xinwo Huang

Hui Li

Feng Liang

Jin-Hong Chen

Mohammed Boudjatit

Gary Eppler

Younane N Abousleiman

Chao Liu

Mohammed Abudullah Bataweel

Huseyin Onur Balan

Shuo Zhang

Jose I Rueda

Houzhu Zhang

Zhuang Sun

Lorne Davis

Jin Ge

Methods and systems are disclosed. The methods may include determining a first sequence of permeabilities by subjecting a rock sample to a first sequence of confining stress, axial stress, pore pressure (CSASPP) triplets and determining a first rock parameter using the first sequence of permeabilities, the first sequence of CSASPP triplets, and a first permeability model. The methods may further include determining a second sequence of permeabilities by subjecting the rock sample to a second sequence of CSASPP triplets and determining a second rock parameter using the second sequence of permeabilities, the second sequence of CSASPP triplets, and the first permeability model. The method may still further include determining an in situ permeability for an in situ rock based on an initial permeability, a second stress sensitivity parameter, a first stress sensitivity parameter, a confining stress value, axial stress values, a pore pressure value, and a second permeability model.

Systems and methods to determine permeability of rock under anisotropic stress

Wellbore treatment fluids are provided that include an aqueous component and an amphiphilic hyperbranched copolymer comprising the polymerized reaction product of at least a first monomer and a second monomer, where the first monomer comprises at least one surface reactive end group chosen from the group consisting of carboxylates, phosphonates, sulfonates, and zwitterions. Also provided are methods of modifying subsurface energy of a carbonate formation using the wellbore treatment fluids.

Wellbore treatment fluids comprising an amphiphilic hyperbranched copolymer

A method for determining a matrix permeability of a subsurface formation, including the steps: acquiring a core from the subsurface formation, imposing a fluid to the core until the core is saturated with the fluid, conducting a pressure-pulse decay (PD) method on an upstream and a downstream side of the core by applying a pressure-pulse on the upstream and the downstream side of the core, and determining the matrix permeability from decays of the pressure-pulses on the upstream side and downstream side, respectively.

Method for determining a matrix permeability of a subsurface formation

Systems and methods for analyzing and modeling natural gas flow in subterranean shale reservoirs. In some embodiments, methodologies and techniques for determining and modeling natural gas flow in shale formations using methodologies and techniques capable of determining natural gas properties related to dual-continuum flow, permeability, and pressure within a subterranean shale reservoir. In some embodiments, the natural gas properties are determined by subjecting a subterranean shale reservoir sample to pulse-decay analysis. In certain embodiments, the methodologies and techniques described may be used in various reservoirs exhibiting macroporosity and microporosity, such as fractured reservoirs and carbonate reservoirs composed of reservoir fluids.

Systems and methods for analyzing natural gas flow in subterranean reservoirs

A method for determining maximum recoverable hydrocarbon (EMR) in a tight reservoir is disclosed. The method includes determining, based on downhole logs, a total measure of hydrocarbon amount within the tight reservoir, determining, by at least attributing fluid loss during core surfacing of the core sample to hydrocarbons, a non-recoverable measure of hydrocarbon amount within a core sample of the tight reservoir, and determining an EMR measure based on the total measure of hydrocarbon amount and the non-recoverable measure of hydrocarbon amount, wherein during the core surfacing pore pressure reduces from a reservoir condition to a surface condition.

Determination of estimated maximum recoverable (EMR) hydrocarbons in unconventional reservoirs

A method for determining SRV and EUR includes: monitoring an amount and a density of a hydrocarbon fluid produced from the production well; obtaining a cumulative amount of the fluid that has accumulated from a beginning of production; obtaining a relationship between the cumulative amount and a square root of the time; determining a deviation point where the relationship changes from linear to non-linear; determining a deviation amount of the fluid corresponding to the deviation point; determining a first density of the hydrocarbon fluid at the beginning of production, a second density at a pore pressure equal to a bottom hole pressure in the production well, a first porosity at the beginning of production, and a second porosity for a pore pressure equal to the bottom hole pressure; and determining SRV and the EUR based on the deviation amount, the first and second densities, and the first and second porosities.

Determination of stimulated reservoir volume and estimated ultimate recovery of hydrocarbons for unconventional reservoirs

A method for determining a rock property includes positioning a core sample in a core sample assembly that is enclosed in a pressurized container with a flow inlet, a flow outlet, and a pressurized fluid inlet fluidly coupled to a pressurized fluid reservoir that includes a pressurized fluid pump; sequentially performing at least three test operations on the core sample; at each of the at least three test operations, measuring an inlet pressure at the flow inlet, measuring an outlet pressure at the flow outlet, and measuring a confining pressure within the pressurized container; and determining a permeability of the core sample based at least in part on at least one of the measured inlet pressures, at least one of the measured outlet pressures, and at least one of the measured confining pressures.

Determining rock properties

Systems, methods, and apparatus for determining permeability of subsurface formations are provided. In one aspect, a method includes: positioning a sample of the subsurface formation in a measurement cell, fluidly connecting an inlet and an outlet of the sample to an upstream reservoir and a downstream reservoir, respectively, flowing a fluid through the sample from the upstream reservoir to the downstream reservoir, measuring changes of an upstream pressure associated with the upstream reservoir and a downstream pressure associated with the downstream reservoir in a measurement time period, and determining a matrix permeability of the subsurface formation based on measurement data before the upstream pressure and the downstream pressure merge at a merging time point.

Determining matrix permeability of subsurface formations

A method for determining stress-dependent permeability includes providing a core sample in a pressurized core container of a testing apparatus and generating a steady-state flow of gas from an upstream reservoir in the testing apparatus along an axial direction through the pressurized core container into a downstream reservoir in the testing apparatus. During the steady-state flow, an inlet pressure at an inlet to the core sample, an outlet pressure at an outlet of the core sample, and a midpoint pressure at a midpoint of the core sample are measured. The stress-dependent permeability is calculated from a flow rate of the gas through the core sample and the measurements of the inlet pressure, the outlet pressure, and the midpoint pressure.

Method and apparatus for measuring stress dependency of shale permeability with steady-state flow

Methods and systems for increasing normalized production rate of an oil and gas reservoir by optimizing a pressure drawdown of a subsurface formation are disclosed. The methods include determining permeability of the subsurface formation as a function of effective stresses, determining a stress sensitivity factor for the core sample, upscaling the sensitive stress factor, determining the optimum pressure drawdown for the subsurface formation, and controlling the pressure drawdown in a field operation such that it does not exceed the optimum pressure drawdown for the subsurface formation.

Methods and systems for determining optimum pressure drawdown in a production well for a shale gas reservoir

Methods and systems for determining fracture and matrix permeability of a subsurface formation. The system includes two upstream reservoirs and two downstream reservoirs, and a sample cell connecting to the reservoirs with valves. The sample cell has a confining pressure (CF) from a fluid. A horizontal plug sample with sleeve is placed in a measurement cell with the confining fluid (CF). A pressure gauge is connected to the small upstream reservoir, and a pressure gauge is connected to the small downstream reservoir. The results provide two sets of effective-stress-dependent permeability values (including fracture permeability and matrix permeability, respectively) for characterizing the reservoir properties.

Methods and systems for determining fracture and matrix permeability of a subsurface formation

Systems and methods for determining shear failure of a rock formation are disclosed. The method includes receiving, by a processor, a plurality of parameters related to physical properties of the rock formation, applying the plurality of parameters to a predetermined failure criterion, and determining shear failure of the rock formation based on the failure criterion. In some embodiments the failure criterion is a modified Hoek-Brown failure criterion that takes into consideration an intermediate principal stress, and the difference between normal stresses and an average confining stress.

Systems and methods for predicting shear failure of a rock formation

The present disclosure describes methods and systems, including computer-implemented methods, computer program products, and computer systems, for analyzing a rock sample from a hydrocarbon reservoir. One method includes: subjecting the rock sample to a first effective stress without exceeding the effective stress under reservoir conditions of the hydrocarbon reservoir; measuring a first permeability of the sample at the first effective stress; increasing the effective stress on the sample to a second effective stress without exceeding the effective stress under reservoir conditions of the hydrocarbon reservoir; measuring a second permeability of the sample at the second effective stress; reducing the effective stress on the sample from the second effective stress to a third effective stress without exceeding the effective stress under reservoir conditions of the hydrocarbon reservoir; measuring a third permeability of the sample at the third effective stress; and distinguishing between a natural fracture and an artificial fracture in the sample based on the first and third permeabilities.

Analyzing fractured rock samples

Methods and systems for detecting leakage in a permeability measurement system. The method includes connecting a plurality of flow lines to a first dimension of a core sample assembly, connecting one or more flow lines to a second dimension of the core sample assembly, placing the core sample assembly with the connections in a measurement cell such that the flow lines are accessible from outside of the measurement cell, connecting one or more gas sensors to one end of each of the flow lines, connecting an inlet of the measurement cell to a gas tank, setting fluid pressure inside the measurement cell to a predetermined value, and detecting a leakage in the core sample assembly by the one or more gas sensors coupled to the flow lines.

Growing community of inventors

Katy, TX, United States of America

Hui-Hai Liu