Landmark Graphics Corporation

Halliburton Energy Services, Inc.

Richard Edward Hinkley

Graham Christopher Fleming

Terry Wayne Wong

Amit Kumar

Travis St George Ramsay

Dominic Camilleri

Qinghua Wang

James William Watts

Kefei Wang

Wei David Liu

Erdinc Eker

A fluid injection process for injecting fluid into a wellbore can be adjusted based on relative permeability. An actual trapped gas saturation of a formation can be determined from a maximum gas saturation, a maximum trapped gas saturation, and an actual gas saturation. A pseudo-maximum gas saturation can be determined from the actual trapped gas saturation, the maximum trapped gas saturation, and actual gas saturation. A relative permeability of the formation can be determined by mapping the pseudo-maximum gas saturation along a drainage curve. The fluid injection process can be adjusted based on the relative permeability.

Adjusting fluid injection into a wellbore based on relative permeability of a formation

A three-dimensional reservoir simulator used for automated upscaling relative permeability and capillary pressure in multi-porosity systems comprising disparate rock-types. A coarse-scale single-porosity model incorporating multi-porosity model properties may be derived from a fine-scale single-porosity model based, at least in part, on simulation of a model comprising data from one or more regions of interest. Real-world and laboratory measurements of the one or more regions of interest may be provided to the fine-scale single-porosity simulation model and the fine-scale single-porosity model may be subjected to one or more fractional flow simulation processes and one or more displacement simulation processes. The fine-scale model properties may be modified based, at least in part, on the results of the one or more fractional flow simulation processes and one or more displacement simulation processes. Coarse scale-model properties may be derived from the fine-scale single-porosity model properties by upscaling the fine-scale single-porosity model. The coarse-scale single-porosity simulation model incorporating multi-porosity model properties may be used to improve operational decision-making, including drilling operations and reservoir management.

Automated upscaling of relative permeability and capillary pressure in multi-porosity systems

Systems, methods, and computer-readable media for forecasting a time to complete a simulation of a reservoir simulation model. A processor can run a simulation of a reservoir simulation model for a first predetermined period of time associated with a first computation step of the simulation. The processor can measure a performance result of the simulation for the first predetermined period of time. The performance result can include an elapsed wall clock time and a timespan simulated. The processor can then forecast a remaining time to complete the simulation of the reservoir simulation model based on the performance result.

Time-to-finish simulation forecaster

In some embodiments, a system, as well as a method and an article, may operate to generate map values for a plurality of parameters corresponding to respective grid blocks of a reservoir, wherein the values have been previously generated based on an initial simulation result from a model of the reservoir; to generate a sector surrogate model that includes a subset of grid blocks of the reservoir based on a criterion for identifying grid blocks that negatively affect simulation of the reservoir; to provide data inputs to execute a simulation of the reservoir using the sector surrogate model; and to generate revised data inputs, based on results of the simulation of the reservoir using the sector surrogate model, to use in a subsequent simulation using the model of the reservoir. Additional apparatus, systems, and methods are disclosed.

Model tuning using boundary flux sector surrogates

Simulation system and method for a reservoir represented by a model having a plurality of matrix nodes, a plurality of fracture nodes, a fracture zone and a fracture-free zone are described. One embodiment includes computer-implemented steps of, for each of a plurality of matrix nodes in interconnected zones, characterizing the matrix nodes as dual matrix nodes or non-dual matrix nodes. Dual matrix nodes may be treated as a block and eliminated, after which the coefficient matrix and RHS vector for the model are updated. In-fill patterns between and among fracture nodes and non-dual matrix nodes resulting from the elimination are determined. For non-dual matrix nodes, the nodes are merged to a fracture grid, after which the coefficient matrix and RHS vector for the model are updated accordingly. The resultant linear system is linearly solved, and backsolving is performed for any eliminated dual matrix nodes.

Growing community of inventors

Houston, TX, United States of America

Richard Edward Hinkley