Abstract: A method comprises measuring a pressure at a plurality of times and a measured flow rate in a well. A measured productivity index (PI) is determined based, at least in part, on the measured flow rate and the pressure at the plurality of times. A flow rate at a second time is simulated, and a fluid pressure at the second time and a third time is simulated. A simulated PI is simulated based, at least in part, on the flow rate at the second time, and the fluid pressure at the second time and at the third time. An updated reservoir simulation model is generated by updating at least one parameter of the reservoir simulation model based, at least in part, on a difference between the measured PI and the simulated PI.

Abstract: Systems and methods include a computer-implemented method for generating a detailed heterogeneities map of a main reservoir. Pressure data for multiple wells of a main reservoir is received during a simultaneous field shut-in of the multiple wells. A scaled rate of change of pressure for each well is determined using the pressure data for each well. Rates of change of pressure for the multiple wells are plotted using the scaled rates of change of pressure. Clusters of wells having rates of change of pressure within a threshold difference of other wells in a given cluster are determined based on the plotting. A detailed heterogeneities map of the main reservoir is generated based the clusters of wells. The heterogeneities map defines heterogeneous regions. Each region contains a set of wells assigned to the heterogeneous region based on the wells having similar rates of change of pressure.

Abstract: Systems and methods include a computer-implemented method for generating a detailed heterogeneities map of a main reservoir. Pressure data for multiple wells of a main reservoir is received during a simultaneous field shut-in of the multiple wells. A scaled rate of change of pressure for each well is determined using the pressure data for each well. Rates of change of pressure for the multiple wells are plotted using the scaled rates of change of pressure. Clusters of wells having rates of change of pressure within a threshold difference of other wells in a given cluster are determined based on the plotting. A detailed heterogeneities map of the main reservoir is generated based the clusters of wells. The heterogeneities map defines heterogeneous regions. Each region contains a set of wells assigned to the heterogeneous region based on the wells having similar rates of change of pressure.

Abstract: Methods for simulation of hydrocarbon systems having a sharply varying viscosity gradient include receiving, by a computer system, Neutron Magnetic Resonance (NMR) logs for hydrocarbon wells in an oilfield. The computer system identifies viscosity regions of hydrocarbons present within the hydrocarbon wells based on the NMR logs. The computer system determines equation of state (EOS) parameters based on compositional analysis of pressure-volume-temperature (PVT) samples obtained from the hydrocarbon wells. The computer system generates a three-dimensional (3D) model of the oilfield, using as inputs, the viscosity regions, the EOS parameters, and a fluid composition gradient with respect to a depth within each viscosity region. The computer system determines a landing depth from the surface of the Earth for operation of peripheral water injectors based on simulating the 3D viscosity model.

Abstract: Embodiments herein relate to identifying occurrence of a trigger condition related to an existing physical well. Embodiments further relate to simulating, based on identification of the occurrence of the trigger condition, a plurality of computer-simulated ancillary wells in a vicinity of the existing physical well. Embodiments further relate to determining one or more simulated parameters related to respective ones of the plurality of computer-simulated ancillary wells. Embodiments further relate to determining, based on the one or more simulated parameters, a parameter of a sidetrack well that is to be related to the existing physical well. Embodiments further relate to outputting an indication of the parameter of the sidetrack well. Other embodiments may be described or claimed.

Abstract: Systems and methods include a computer-implemented method for predicting values. A numerical simulation model is generated based on observed production rates and flowing pressure and build-up (FPBU) test rates. A simulated diagnostic plot is generated using simulated FPBU data extracted from the numerical simulation model. Simulation model properties of the numerical simulation model are adjusted until the simulated diagnostic plot matches within a tolerance to an observed FPBU diagnostic plot. Predicted values including a static pressure, a water cut, and a gas-oil rate (GOR) are predicted using the simulated FPBU data. Observed data of a reservoir is reviewed and quality-checked based on comparing the predicted values within a tolerance of the observed data.

Abstract: Certain methods to determine wellbore relative permeability ratio from wellbore drilling data are described. A section of a wellbore is drilled in a subterranean zone including a subsurface reservoir in which hydrocarbons are entrapped. The hydrocarbons include a multiphase fluid including oil phase and water phase. A relevant suite of logs of rock in the section of the wellbore is determined. Water saturation is determined from the relevant suite of logs. A relative permeability ratio of the rock in the section to a flow of the oil phase and the water phase is determined. Using the relative permeability ratio, a flow rate of the oil phase or a flow rate of the water phase through the rock is determined.

Abstract: Some implementations provide a method including: accessing measurement data that characterize one or more features of a reservoir, wherein the measurement data are from more than well locations of the reservoir and from a range of depths inside the reservoir; detecting portions of the measurement data that characterize the one or more features with a statistical metric that is below a pre-determined threshold; based on removing the portions of the measurement data, identifying a plurality of layers along the range of depths of the reservoir; within each layer of the plurality of layers, grouping the measurements data among a plurality of clusters, each corresponding to a flow unit (FU) and determined by a machine learning algorithm; generating a three-dimensional (3D) permeability model of the reservoir based on the FU of each layer and a saturation height function; and simulating a performance of the reservoir based on the 3D permeability model.

Abstract: Methods for determining composite matrix-fracture properties of naturally fractured reservoirs include obtaining, by a computer system, measured hydrocarbon data from one or more hydrocarbon wells using one or more formation evaluation tools. The computer system generates composite matrix-fracture properties of the one or more hydrocarbon wells using numerical simulation. The composite matrix-fracture properties include at least one of composite matrix-fracture permeability, composite matrix-fracture water saturation, composite matrix-fracture pressure, or composite matrix-fracture mobility of the one or more hydrocarbon wells. The computer system performs history matching for the one or more hydrocarbon wells by comparing the measured hydrocarbon data to the composite matrix-fracture properties. A display device of the computer system generates a graphical representation of results of the history matching.

Abstract: Systems and methods are provided for determining and presenting field view history-matched well quality data. In one embodiment, a method includes receiving well data for a plurality of wells and performing a plurality of functional operations including a trend operation to determine well groups using pattern recognition of well time lapse pressure trends, the trend operation configured to identify at least one connected reservoir region (CRR), a geo-probe integration operation configured to integrate data for each CRR and evaluate a three-dimensional (3D) static model for wells; a history match advisor operation to generate a combined display of time dependent and depth dependent representation of the well data; a spatio-temporal operation configured to generate a space and time visualization of the well data; a front operation configured to track simulated injected fluid front; and an insight operation configured to report static changes between a well field model and history match model.

Abstract: Methods, systems, and computer-readable medium to perform operations including obtaining data identifying a time-lapse average pressure for each well of a plurality of wells of a reservoir; determining a plurality of homogenous trends of the data; clustering the data into a plurality of groups based on the homogenous trends, each group corresponding to a respective trend; and generating a connected reservoir region map that includes a plurality of connected reservoir regions (CRR) that each correspond to a group of the plurality of groups, each CRR includes a subset of the plurality of wells that corresponds to the respective group of the CRR, wherein each CRR is associated with a homogeneous pressure response.

Abstract: Methods for simulation of hydrocarbon systems having a sharply varying viscosity gradient include receiving, by a computer system, Neutron Magnetic Resonance (NMR) logs for hydrocarbon wells in an oilfield. The computer system identifies viscosity regions of hydrocarbons present within the hydrocarbon wells based on the NMR logs. The computer system determines equation of state (EOS) parameters based on compositional analysis of pressure-volume-temperature (PVT) samples obtained from the hydrocarbon wells. The computer system generates a three-dimensional (3D) model of the oilfield, using as inputs, the viscosity regions, the EOS parameters, and a fluid composition gradient with respect to a depth within each viscosity region. The computer system determines a landing depth from the surface of the Earth for operation of peripheral water injectors based on simulating the 3D viscosity model.

Abstract: Disclosed are methods, systems, and computer-readable medium to perform operations including: generating a grid representation of a reservoir model comprising a simulation well, the grid comprising a plurality of grid-blocks, wherein the simulation well is centered in grid-block (i) of the plurality of grid-blocks; simulating, using the grid representation, grid-block pressures for the plurality of grid-blocks over a plurality of time steps; calculating an equivalent radius (ro*) for a grid-block (i+1), wherein the grid-block (i+1) is adjacent to the grid-block (i); and calculating, based on the equivalent radius and a grid-block (i+1) pressure, a shut-in bottom-hole pressure (SBHP) for the simulation well.

Abstract: Disclosed are methods, systems, and computer-readable medium to perform operations including: generating a grid representation of a reservoir model comprising a simulation well, the grid comprising a plurality of grid-blocks, wherein the simulation well is centered in grid-block (i) of the plurality of grid-blocks; simulating, using the grid representation, grid-block pressures for the plurality of grid-blocks over a plurality of time steps; calculating an equivalent radius (ro*) for a grid-block (i+1), wherein the grid-block (i+1) is adjacent to the grid-block (i); and calculating, based on the equivalent radius and a grid-block (i+1) pressure, a shut-in bottom-hole pressure (SBHP) for the simulation well.

Abstract: Certain methods to determine wellbore relative permeability ratio from wellbore drilling data are described. A section of a wellbore is drilled in a subterranean zone including a subsurface reservoir in which hydrocarbons are entrapped. The hydrocarbons include a multiphase fluid including oil phase and water phase. A relevant suite of logs of rock in the section of the wellbore is determined. Water saturation is determined from the relevant suite of logs. A relative permeability ratio of the rock in the section to a flow of the oil phase and the water phase is determined. Using the relative permeability ratio, a flow rate of the oil phase or a flow rate of the water phase through the rock is determined.

Abstract: Methods, systems, and computer-readable medium to perform operations including obtaining data identifying a time-lapse average pressure for each well of a plurality of wells of a reservoir; determining a plurality of homogenous trends of the data; clustering the data into a plurality of groups based on the homogenous trends, each group corresponding to a respective trend; and generating a connected reservoir region map that includes a plurality of connected reservoir regions (CRR) that each correspond to a group of the plurality of groups, each CRR includes a subset of the plurality of wells that corresponds to the respective group of the CRR, wherein each CRR is associated with a homogeneous pressure response.

Abstract: Techniques to generate dynamically calibrated geo-models green fields are described. A geo-model representing a field on which wells are drilled in a hydrocarbon-bearing formation adjusted to generate multiple adjusted geo-models. Each adjusted geo-model represents a variant of the numerical geo-model. Using each adjusted geo-model, multiple simulated rates of change of bottomhole pressures over time in a well drilled in the hydrocarbon-bearing formation are determined. A measured rate of change of bottomhole pressures over time in the well is compared with the multiple simulated rates of change of bottomhole pressures over time in the well. Based on a result of the comparing, the adjusted geo-model that yielded simulated rates of change of bottomhole pressures that best matched the measured rate of change of bottomhole pressure is identified.

Abstract: The present disclosure describes methods and systems, including computer-implemented methods, computer program products, and computer systems, for improving water break-though time predictions. One computer-implemented method includes obtaining, by a hardware data processing apparatus, a plurality of initial relative permeability data; determining, by the hardware data processing apparatus, viscosity data; determining, by the hardware data processing apparatus, a flood-front saturation point based on the viscosity data and the initial relative permeability data; and generating, by the hardware data processing apparatus, a plurality of corrected relative permeability data based on the plurality of initial relative permeability data and the critical fractional flow point, wherein the plurality of the corrected relative permeability data are used to simulate water break-through time.

Abstract: Techniques to generate dynamically calibrated geo-models green fields are described. A geo-model representing a field on which wells are drilled in a hydrocarbon-bearing formation adjusted to generate multiple adjusted geo-models. Each adjusted geo-model represents a variant of the numerical geo-model. Using each adjusted geo-model, multiple simulated rates of change of bottomhole pressures over time in a well drilled in the hydrocarbon-bearing formation are determined. A measured rate of change of bottomhole pressures over time in the well is compared with the multiple simulated rates of change of bottomhole pressures over time in the well. Based on a result of the comparing, the adjusted geo-model that yielded simulated rates of change of bottomhole pressures that best matched the measured rate of change of bottomhole pressure is identified.

Abstract: The present disclosure describes methods and systems, including computer-implemented methods, computer program products, and computer systems, for improving water break-though time predictions. One computer-implemented method includes obtaining, by a hardware data processing apparatus, a plurality of initial relative permeability data; determining, by the hardware data processing apparatus, viscosity data; determining, by the hardware data processing apparatus, a flood-front saturation point based on the viscosity data and the initial relative permeability data; and generating, by the hardware data processing apparatus, a plurality of corrected relative permeability data based on the plurality of initial relative permeability data and the critical fractional flow point, wherein the plurality of the corrected relative permeability data are used to simulate water break-through time.