Baker Hughes Oilfield Operations LLC

General Electric Company

Ge Inspection Technologies, Gmbh

Glen Murrell

Robert Klenner

Mahendra L Joshi

Naresh Sundaram Iyer

Steven Hector Azzaro

Alireza Shahkarami

Guoxiang Liu

Hayley Stephenson

Robert Carl Lloyd Klenner

Guodong Jin

Umesh Prasad

Thomas Nguyen

Seehong Ong

Panqing Gao

Ghazal Izadi

Syed Shujath Ali

Mahendra Joshi

Steven Azzaro

Methods and systems include using downhole data to determine a static bulk modulus of dry rock or rock frame in a porous formation and determine a static bulk modulus of grain minerals in the porous formation. Biot's coefficient for the porous formation can be determined based on the static bulk modulus of dry rock or rock frame and the static bulk modulus of grain minerals. Effective stress of the porous formation can be determined based on Biot's coefficient. Effective stress of the porous formation is used in geomechanical applications, including hydraulic fracturing, wellbore stability analysis, and reservoir integrity assessments.

Geomechanical applications using Biots coefficient based on advanced downhole logging measurements

A method is provided for monitoring the occurrence of pressure anomalies due to FDI in near real time during a hydraulic fracturing operation carried out on an active well that is located near one or more passive monitoring wells. The method includes the steps of obtaining raw pressure sensor data from the one or more passive monitoring wells, processing the pressure sensor data with the FDI analysis module, and determining if the rate of change for averaged pressure sensor data exceeds a preset threshold value that indicates the likelihood of a pressure anomaly. The methods can be configured to autonomously alert an operator of the likelihood of a pressure anomaly and with guidance on resolving the anomalies.

Real time monitoring of fracture driven interference

A method is provided for controlling the operation of an offset well located near an active well that is undergoing a hydraulic fracturing operation that may produce a fracture driven interference (FDI) event to the offset well. The method includes providing an FDI intervention system that includes a computer-implemented predictive model for determining a risk of the FDI event occurring during the hydraulic fracturing operation, calculating a risk-weighted FDI event cost of the FDI event impacting production from the offset well, and calculating a defensive intervention implementation cost to apply a defensive intervention on the offset well to mitigate harm from an FDI event. The method includes calculating a cost comparison based on a comparison of the defensive intervention implementation cost and the risk-weighted FDI event cost. The method concludes with automatically controlling the operation of the offset well with the FDI intervention system based on the cost comparison.

Automatic well control based on detection of fracture driven interference

The current subject matter is related to optimizing resource (e.g., steam) allocation within steam assisted gravity drainage (SAGD) system, and predicting future oil production from production wells of the SAGD system. In some embodiments data characterizing a hypothetical rate of steam injection into injection wells of the SAGD system can be applied within a capacitance resistance model (CRM) to determine an estimated rate of future fluid production, the fluid being a mixture of oil and water. An emulsion viscosity, as well as the estimate rate of future fluid production, can be applied within a Koval fractional flow model to determine an estimate rate of future oil production. In some cases, the hypothetical rate of steam injection can be optimized based on an optimization objective, e.g., a steam-to-oil ratio (SOR).

Rapid steam allocation management and optimization for oil sands

A system and method for extracting a resource from a reservoir repeatedly alternates between injecting a fluid and injecting a gas into the reservoir. A rate and/or an amount of each of the fluid and the gas that is injected into the reservoir is defined by a first fluid-and-gas ratio function that designates different ratios as a function of time. The ratios designate the rate and/or the amount of the fluid that is injected into the reservoir to the rate and/or the amount of the gas that is injected into the reservoir. The rate and/or the amount at which the fluid and/or the gas is injected into the reservoir is changed according to the ratios designated by the first fluid-and-gas ratio function as time progresses.

System and method for extracting resources from a reservoir through customized ratios of fluid and gas injections

System includes one or more processors that are configured to perform iterations of the following until a predetermined condition is satisfied. The one or more processors are configured to select a modified trial schedule. The modified trial schedule is selected based on initial fluid-extraction data and initial trial schedules and, if available, prior modified trial schedules and prior modified fluid-extraction data from prior iterations. The one or more processors are configured to receive modified fluid-extraction data generated by execution of the modified trial schedule with a designated model of the reservoir. The one or more processors are also configured to update the surrogate model with the modified fluid-extraction data and the modified trial schedule. For at least a plurality of the iterations, the modified trial schedule is selected, at least in part, to reduce uncertainty in a sample space as characterized by the surrogate model.

System and method for generating a schedule to extract a resource fluid from a reservoir

A method includes a first injection phase that includes injecting a first gas-based fluid into a subterranean formation at a first pressure that exceeds a fracture pressure of the subterranean formation. The method also includes a second injection phase that includes injecting a second gas-based fracturing fluid into the subterranean formation at a second pressure that exceeds a minimum miscibility pressure of the second gas-based fluid, followed by a shut in period. The method further includes a third injection phase that includes injecting the first gas-based fluid or a third gas-based fluid into the subterranean formation at the first fracture pressure or at a third pressure exceeding the fracture pressure of the subterranean formation. The first gas-based fluid, second gas-based fluid, and third gas-based fluid include carbon dioxide (CO).

Three-phase method for injecting carbon dioxide into oil reservoirs

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Oklahoma City, OK, United States of America

Glen Murrell