Schlumberger Technology Corporation

Chevron U.s.a. Inc.

Schlumberger Canada Limited

Services Petroliers Schlumberger

Logined B.v.

Terry Wayne Stone

Garfield Bowen

William John Bailey

Tom Jonsthovel

Benoit Couet

Kashif Rashid

George Albert Brown

James Bennett

David J Browning

David C Bradley

Nikolay Morozov

James S Nolen

Hewei Tang

Yih-Bor Chang

William J Bailey

George A Brown

A method may include obtaining data representing flow rates for a plurality of flow control devices. The method also includes determining total molar rates for a plurality of flows through pipe segments associated with each of the flow control devices based on the obtained data. The method also includes determining initial flow control device constraints based on the total molar rates for the plurality of flow control devices. The method also includes determining that one or more wellhead constraints would be violated based on the flow control device constraints. The method also includes determining adjusted flow control device constraints that result in the satisfaction of one or more wellhead constraints or constraints of others of the plurality of flow control devices. The method also includes determining an adjusted flow rate based on the adjusted device constraints that satisfy the wellhead and the flow control device constraints.

Method for obtaining unique constraints to adjust flow control in a wellbore

Methods, computing systems, and computer-readable media for determining flow control device settings. The method may include obtaining data representing flow rates for a plurality of flow control devices; determining total molar rates for a plurality of flows through pipe segments associated with each of the flow control devices based on the obtained data; determining initial flow control device constraints based on the total molar rates for the plurality of flow control devices; determining that one or more wellhead constraints would be violated based on the flow control device constraints; determining adjusted flow control device constraints that result in the satisfaction of one or more wellhead constraints or constraints of others of the plurality of flow control devices; determining an adjusted flow rate based on the adjusted device constraints that satisfy the wellhead and the flow control device constraints; and executing a computer-based instruction to set one or more wellhead settings and flow control device valve settings based on the adjusted flow control device constraints.

A method for performing a modified two point flux approximation scheme is disclosed. The method includes: obtaining a first pressure value for a first neighbor cell and a second pressure value for a second neighbor cell, where the first neighbor cell has a first value of a reservoir property and the second neighbor cell as a second value of the reservoir property; determining a first weight using the first pressure value and a second weight using the second pressure value; calculating a third value of the reservoir property as a weighted average of the first value and the second value; and applying the third value to the first neighbor cell.

Enhanced two point flux approximation scheme for reservoir simulation

Methods of exploiting a formation containing a reservoir of hydrocarbons utilize a gas-liquid drift-flux (DF) model for a multi-segmented wellbore (MSW). The DF model is provided for use in conjunction with a reservoir simulator. The DF model is configured to account for pipe inclinations of the MSW between &#x2212;90&#xb0; and +90&#xb0; including horizontal or near-horizontal wellbores in addition to vertical and slanted wellbores. The DF model is based on mixture velocity as opposed to superficial velocities, thereby permitting the DF model to be integrated with reservoir models that utilize mixture velocity. The DF model can also be continuous and differentiable over all primary variables.

Methods and systems for reservoir and wellbore simulation

A method, apparatus, and program product to determine distribution of a plurality of components amongst a plurality of phases for a multi-component, multi-phase system including a multi-component, multi-phase fluid. A plurality of phase boundaries of the multi-component, multi-phase fluid and a vapor-liquid equilibrium (VLE) are determined based on a plurality of geophysical parameters associated with an oilfield and using one or more computer processors, including by determining hydrocarbon partitioning in a water phase, based in part on applying empirical equilibrium multi-phase mole fraction ratios (K-values) of the multi-component, multi-phase system that are functions of temperature and pressure only. In addition, an amount of at least one fluid component distributed in a plurality of phases of the multi-component, multi-phase system is predicted by solving a set of flash equations with the one or more computer processors based on the plurality of phase boundaries.

Extended isenthalpic and/or isothermal flash calculation for hydrocarbon components that are soluble in oil, gas and water

A method and an apparatus for managing a subterranean formation including collecting information about a flow control valve in a wellbore traversing the formation, adjusting the valve in response to the information wherein the adjusting includes a Newton method, a pattern search method, or a proxy-optimization method. In some embodiments, adjusting comprises changing the effective cross sectional area of the valve. A method and an apparatus for managing a subterranean formation including collecting information about an inflow control valve in a wellbore traversing the reservoir and controlling the valve, wherein the control includes a direct-continuous approach or a pseudo-index approach.

Method of optimization of flow control valves and inflow control devices in a single well or a group of wells

Design and control of well systems with multiple tubing strings is described. An example system models multiple tubing strings in wellbores as segments, with multiple control points selectively located among the segments. Each segment is modeled as one or more equations that describe characteristics of a fluid resource associated with the segment. The system can predict flow of fluids and energy in a wellbore by solving physical conservation equations subject to specified conditions. The system models multiple control points, and solves the equations to convergence to satisfy injection and production targets and specified constraints. Results may be used to improve production of the resource. The system can apply a variety of strategies to model wells via multiple control points, including conservation of mass and energy models, a global phase-component partitioning model, a conductive heat transfer model, a pseudo-pressure model, a non-Darcy flow model, a phase separation model, and so forth.

Control of multiple tubing string well systems

System and method for producing fluids from a hydrocarbon reservoir where an injector well segment and parallel underlying producer well segment are both completed with slotted liners. The injector and producer segments are logically partitioned into corresponding sections to define a plurality of injector-producer section pairs. Injection tubing strings supply stimulating fluid (e.g., saturated steam) to associated sections of the injector segment for injection into the hydrocarbon reservoir. Surface-located control devices control the pressure of the stimulating fluid flowing through the respective injection tubing strings. Production tubing strings (with the aid of artificial lift) carry fluids produced from associated sections of the producer segment. A plurality of controllers is provided for the injector-producer section pairs to control at least one process variable (e.g., interwell subcool temperature) associated with respective injector-producer section pairs over time by adjusting control variables that dictate operation of the control devices for the injection tubing strings.

Hydrocarbon recovery employing an injection well and a production well having multiple tubing strings with active feedback control

One or more computer-readable media include computer-executable instructions to instruct a computing system to iteratively solve a system of equations that model a wellbore and fracture network in a reservoir where the system of equations includes equations for multiphase flow in a porous medium, equations for multiphase flow between a fracture and a wellbore, and equations for multiphase flow between a formation of a reservoir and a fracture. Various other apparatuses, systems, methods, etc., are also disclosed.

Multiphase flow in a wellbore and connected hydraulic fracture

A method can include identifying a discrete natural fracture in a three-dimensional environment that includes a reservoir modeled by a three-dimensional grid model, representing the discrete natural fracture via a multisegment model in a two-dimensional region within the three-dimensional grid model, defining at least one connection for fluid communication between the multisegment model and the three-dimensional grid model, defining boundary conditions for the multisegment model, and solving the multisegment model subject to the at least one connection and the boundary conditions to provide values for fluid flow in the two-dimensional region. Various other apparatuses, systems, methods, etc., are also disclosed.

Multisegment fractures

A method of analyzing phase transitions of fluid in an oilfield operation of an oilfield. The method includes determining phase boundaries of a multi-component multi-phase system based on geophysical parameters associated with the oilfield, predicting an amount of at least one fluid component in a liquid fluid phase of the multi-component multi-phase system by solving a set of flash equations based on phase boundaries, and performing the oilfield operation based on the predicted amount.

Multi-component multi-phase fluid analysis using flash method

A method for reservoir simulation that includes applying fraction boundary conditions at a surface of a grid representing the subterranean reservoir, finding a rock state, representing initial rock displacements and porosity in the grid, that satisfies a first equation of VNTG&#x3c6;=VNTG&#x3c6;=PV, initializing the grid based on the rock state to generate an initialized grid, determining a set of rock displacements based on the initialized grid, and generating a simulation result based on the rock displacements, where an operation in the subterranean reservoir is performed based on the simulation result.

Simulation method and apparatus for determining subsidence in a reservoir

A reservoir simulator first estimates rock displacement parameters (u, v, and w) representing rock movement in the x, y, and z directions. When the rock displacement parameters (u, v, w) are determined, '&#x3b5;' (the 'x,y,z elongation strains') and '&#x3b3;' (the 'shear strains') are determined since &#x201c;&#x3b5;&#x201d; and &#x201c;&#x3b3;&#x201d; are function of &#x201c;u&#x201d;, &#x201c;v&#x201d;, and &#x201c;w&#x201d; When &#x201c;&#x3b5;&#x201d; and &#x201c;&#x3b3;&#x201d; are determined, &#x201c;&#x3c3;&#x201d; (the &#x2018;elastic normal rock stress in x,y,z directions&#x2019;) and &#x201c;&#x3c4;&#x201d; (the &#x2018;elastic shear stress&#x2019;) are determined since &#x201c;&#x3c3;&#x201d; and &#x201c;&#x3c4;&#x201d; are a function of &#x201c;&#x3b5;&#x201d; and &#x201c;&#x3b3;&#x201d;. When &#x201c;&#x3c3;&#x201d; and &#x201c;&#x3c4;&#x201d; are determined, the rock momentum balance differential equations can be solved, since these equations are a function of &#x201c;&#x3c3;&#x201d; and &#x201c;&#x3c4;&#x201d;. When any residuals are substantially equal to zero, the estimated rock displacement parameters (u, v, and w) represent &#x2018;accurate rock displacement parameters&#x2019; for the reservoir. When the rock momentum balance differential equations are solved, the rock displacement parameters (u, v, w), at an advanced time, are known. These rock displacement parameters (u, v, w) represent and characterize &#x2018;subsidence&#x2019; in a seabed floor because subsidence results from rock movement; and rock movement results from withdrawal of oil or other hydrocarbon deposits or other fluids from an Earth formation. This &#x2018;abstract of the disclosure&#x2019; is given for the sole purpose of allowing a patent searcher to easily determine the content of the disclosure in this application.

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Hampshire, United Kingdom

Terry Wayne Stone