Saudi Arabian Oil Company

Dung T Phan

Younane N Abousleiman

Chao Liu

Yanhui Han

Katherine Leigh Hull

Khalid AlRuwaili

Murtadha J AlTammar

Khalid Mohammed Alruwaili

Vladimir Kazei

Systems and methods for determining a connected porosity and a non-connected porosity in a fluid-saturated hydrocarbon reservoir are disclosed. The methods include obtaining at least one rock sample from the fluid-saturated hydrocarbon reservoir, determining, using a petrophysical sample analyzer, at least one petrophysical parameter of the rock sample, and measuring at least one of an elastic wave velocity and an elastic wave attenuation for each of a plurality of wave frequencies. The methods further include determining, using a computer processor, the connected porosity and the non-connected porosity of the rock sample using a dual-porosity single-permeability model based, at least in part, on at least one petrophysical parameter and at least one of the elastic wave velocity and the elastic wave attenuation.

Method for determining connected and non-connected porosities

A method of determining rock matrix and fracture permeability to perform a reservoir fluid flow simulation. The method includes: obtaining a petrophysical characterization of a formation sample, measuring a first and second elastic wave velocity of the formation sample at a first and second frequency, calculating an average rock matrix density and an average porosity of the formation sample, determining a set of calculated elastic wave velocities for the first and second frequencies over a range of candidate permeabilities, and determining a rock matrix permeability and a fracture permeability based on the set of calculated elastic wave velocities at the first and second frequency respectively. The method further including performing a reservoir fluid flow simulation based, at least in part, on at least one of the rock matrix permeability and the fracture permeability.

Method for determining rock matrix and fracture permeability by using poroelastodynamics and density averaging schemes

A method for predicting a formation property of a formation, including the steps of: drilling a first well that penetrates the formation, obtaining well properties from the first well, determining a measured formation property from the first well, determining a correlation function that estimates a predicted formation property from the well properties, wherein the correlation function comprises coefficients, calibrating the correlation function by modifying the coefficients until the predicted formation property best matches the measured formation property, drilling a second well that penetrates the formation, obtaining well properties from the second well, determining the formation property from the second well by applying the correlation function with the modified coefficients to the well properties.

Methods for predicting formation properties

A method includes obtaining total stresses and pore pressures of each porous medium of a formation, determining a first and second set of effective stresses for the formation, determining an individual collapse and fracturing mud weight for each porous medium of the formation using a first set of associated failure criteria, wherein the first set of associated failure criteria are based on the first set of effective stresses, determining an overall collapse and fracturing mud weight for the formation using a second set of associated failure criteria, wherein the second set of associated failure criteria is based on the second set of effective stresses, determining a mud weight window for the formation using the individual collapse mud weight, the individual fracturing mud weight, the overall collapse mud weight, and the overall fracturing mud weight, and transmitting a command to a drilling system based on the mud weight window.

Method for the determination of mud weight window in N-porosity N-permeability formations

A method for evaluating an integrity of a liner disposed in a wellbore, that contacts a formation through a cement layer between the liner and the formation, includes computing a stress on a boundary of the liner by an iteration procedure that implements an analytical solution of stresses on a liner-cement interface and a cement-formation interface using the geometric data, performing numerical simulations using the computational numerical model to calculate a magnitude and distribution of stresses acting on the liner-cement interface and the cement-formation interface, performing numerical simulations with the actual in-situ stresses to replace the mean in-situ stress on the outer boundary of formation layer to calculate magnitude and distribution of stresses acting on the liner-cement and cement-formation interfaces using the calibrated computational mesh and applying the calculated stresses acting on the liner to a liner integrity evaluation model to determine an integrity of the liner at a plurality of stages of the wellbore.

Hybrid procedure for evaluating stress magnitude and distribution on a liner

Systems and methods for predicting a breakdown pressure of a formation and fracturing the formation account for filter cake effects. The systems and methods measure a time-dependent permeability and a time-dependent thickness of a filter cake formed by a first drilling mud. The systems and methods determine a time-dependent permeability model and a time-dependent thickness model of the filter cake. The systems and methods select a breakdown pressure model based on (i) the time-dependent thickness of the filter cake, (ii) the time-dependent permeability of the filter cake, and (iii) the permeability of the formation. The systems and methods use the selected breakdown pressure model to predict the breakdown pressure of the formation and fracture the formation using a drilling fluid having a mud weight associated with the predicted breakdown pressure of the formation.

Fracturing a subsurface formation based on the required breakdown pressure accounting for filter cake

Methods for determining an in-situ pore pressure in a formation rock may include acquiring well log data, calculating a cation-exchange capacity, calculating a mole fraction of fixed charges using the cation-exchange capacity, determining a formation temperature, calculating the in-situ pore pressure, outputting the in-situ pore pressure of the formation rock, and using the in-situ pore pressure in a wellbore stability model to monitor and maintain stability of the formation rock. Corresponding electronic devices may include a computer processor coupled to at least one logging tool, wherein the logging tool is configured to acquire well log data in a formation rock. Non-transitory computer storage mediums may include program instructions, that when executed, may be configured to perform the methods for determining an in-situ pore pressure in a formation rock.

Method of determining in-situ pore pressure in chemically active formations

A method may include determining time-derivative pressure data based on pressure data regarding a pump system that is performing a hydraulic stimulation operation in a geological region. The method may further include determining a moving average value based on the time-derivative pressure data and a predetermined time window. The method may further include determining a flow rate adjustment for the pump system based on the moving average value, an update interval for adjusting flow rates, and a predetermined flow rate rule. A size of the predetermined time window may be different from the update interval. The method may further include using smoothed pressure data to determine time-derivative pressure data. The method may further include determining a flow rate adjustment for the pump system based on the time-derivative pressure data derived from the smoothed pressure data.

Method and system for autonomous flow rate control in hydraulic stimulation operations

Estimating permeability enhancement of a subterranean formation due to presence of an oxidizer in a fracturing fluid, including determining kerogen volume percent in the subterranean formation and estimating fractured kerogen porosity, wherein the fractured kerogen porosity is associated with presence of the oxidizer. The technique includes determining an increase in connected porosity in the subterranean formation correlative with the kerogen vol % and the fractured kerogen porosity.

Determining effect of oxidative hydraulic fracturing

A method for measuring a fracture permeability and a matrix permeability of a naturally fractured cylindrical rock sample, includes sealing both flat ends of the cylindrical sample; immersing the naturally fractured cylindrical rock sample in a fluid, and attaching an axial and a radial strain sensor to the curved surface of the sample. Furthermore, the method includes attaching a signal generator to one flat end of sample, and a signal receiver to the other flat end of the sample, and generating a harmonic excitation using the signal generator at a plurality of frequencies and recording the excitation at each of the plurality of frequencies. The method includes calculating an elastic wave propagation attribute at each of the plurality of frequencies, and inverting the elastic wave propagation attribute at each of the plurality of frequencies to determine the fracture permeability and the matrix permeability of the naturally fractured cylindrical rock sample.

Two methods of determining permeabilities of naturally fractured rocks from laboratory measurements

Systems and methods for determining a time-dependent mud weight window are disclosed. The existence of fractures in formation rock along with a type of the formation rock are used to determine the use of a particular solution to determine the mud weight window at a particular time of a wellbore drilling operation.

Growing community of inventors

Brookshire, TX, United States of America

Dung T Phan