The invention discloses a method for evaluating the difference in gas injection effect of gas injection wells in a carbonate reservoir, aiming at solving the problem that the difference in effect characters of gas injection wells cannot be systematically evaluated in the prior art, and realizing the purposes of systematically and completely evaluating the difference in gas injection effect in the carbonate reservoir and finding out the reason of low efficiency. By means of the invention, reasons for low gas injection efficiency corresponding to different geological classifications are obtained, systematic classification and induction are carried out on the difference in gas injection effect, and gas injection effects are effectively evaluated, so that a sufficient gas injection scheme design basis is provided for subsequent development and production increase, and a significant guiding principle is provided for later-stage gas injection and production increase of the carbonate reservoir.

An unstructured grid model with actual well trajectory of individual multilateral wells of a subsurface reservoir is formed. Well trajectory data obtained during drilling of the wells and corresponding to well trajectory data stored as a structured grid model is provided as an input data set for unstructured grid simulation. The unstructured grid model may be formed in a computerized mainframe processor system, or by parallel reservoir simulation by processor nodes of a multicore processor of parallel processor nodes synchronized and under control of a master node.

Selecting a fracing-plan-to-apply to optimize a complexity index includes identifying a set of controllable input variables that defines a fracing plan. Initial values for the set of controllable input variables are defined. The initial values of the set of controllable input variables are processed to produce an initial stimulated geometry. A complexity estimator is applied to the initial stimulated geometry to produce an initial complexity index, which is evaluated to identify at least one variation from the initial values, which is processed to produce a variation stimulated geometry for each of the at least one variation from the initial values. The complexity estimator is applied to the at least one variation stimulated geometry to produce a variation complexity index for each of the at least one variation from the initial values. The fracing-plan-to-apply is selected from among the initial values and the at least one variation from the initial values.

The present invention relates to a system and method for modelling flow conditions in a well system, the well system being represented by a number of branches (1,1a) conducting hydrocarbons from at least one branch entry point (3,3a) to a branch exit point (2), at least one of said branches constituting a global well system exit point, wherein each branch has a branch entry point (3,3a) being provided with a least one flow inlet (4) and being related to known boundary conditions and with a input flow control unit (7) being related to adjustable flow characteristics for controlling the flow through said input, said boundary conditions including predetermined data concerning at least one of pressure, temperature and flow at said input flow control unit, and said branch conduit includes an branch flow control unit (6), having adjustable flow characteristics for controlling the flow through the branch.

The invention discloses a method for predicting the optimal shut-in duration by coupling fluid flow and geological stress, comprising the following steps: determine basic parameters; obtain the fracture length, fracture width and reservoir stress distribution based on the basic parameters; calculate the oil saturation, pore pressure, and permeability and porosity after coupling change in different shut-in durations on the basis of the principle of fluid-solid coupling; take the oil saturation, pore pressure, and permeability and porosity obtained in Step 3 as initial parameters and calculate the production corresponding to different shut-in time on the basis of the productivity model; finally select the optimal shut-in time based on the principle of fastest cost recovery. The present invention can accurately predict the optimal shut-in duration after fracturing to improve the oil and gas recovery ratio in tight oil and gas reservoirs with difficulty in development and low recovery.

Methods, computing systems, and computer-readable media for predicting pore pressure. As an example, the method includes receiving data representing a subterranean domain, modeling the domain based on the data, ranking the data, testing and validating the model, calibrating the model, and predicting a pore pressure in the domain.

Methods, devices, and systems for tracking lateral motion of a nuclear magnetic resonance (NMR) tool are disclosed. In some embodiments, a phase shift for one or more spin-echo signals received by the NMR tool is detected during a velocity measurement sequence that corresponds to at least one formation measurement sequence. A lateral velocity of the NMR tool is determined based, at least in part, on the detected phase shift.

A porous micromodel network to simulate formation flows includes a substrate, two or more porous micromodels formed on the substrate and a fluid inlet formed on the substrate. The first porous micromodel defines a first fluidic flow pathway and is representative of a first hydrocarbon-carrying formation. Flow through the first fluidic flow pathway is representative of flow through the first hydrocarbon-carrying formation. The second porous micromodel is fluidically isolated from the first porous micromodel. The second porous micromodel defines a second fluidic flow pathway different from the first fluidic flow pathway. The second porous micromodel is representative of a second hydrocarbon-carrying formation different from the first hydrocarbon-carrying formation. Flow through the second fluidic flow pathway is representative of flow through the second hydrocarbon-carrying formation. The fluid inlet is fluidically configured to simultaneously flow fluid to the first fluidic flow pathway and the second fluidic flow pathway.

The present invention discloses a method for optimizing sensor network node location in a geological CO.sub.2 storage area. In the method, by analyzing data in a monitoring area, such as geological data, geographical data, and meteorological data, analyzing influence factors of a CO.sub.2 leakage event and determining a sensitivity partition, designing different coverage control schemes of monitoring sensor network nodes, or intensively or sparsely arranging sensor monitoring nodes, a coverage network is described and optimally expressed on the basis of Delaunay triangulation. In the method for optimizing sensor network node location in a geological carbon dioxide storage area, the arrangement density of wireless sensor network nodes can be dynamically adjusted according to geological and geographical features of a detection area, and the arrangement optimization of a dynamic monitoring sensor network for coal seam carbon dioxide injection area leakage can be realized. The method reduces node redundancy and communication overheads as much as possible, and has strong network coverage and network connectivity.

Orthogonal unstructured grids are automatically constructed for a field or reservoir model with two types of internal boundaries: complex wells and faults, or other discontinuities. The methodology is used to constructed simulation grids for reservoirs or fields which contains both complex fault planes and multi-lateral wells. A hierarchical grid point generation, prioritization, conflict point removal system is provided enabling the use of unconstrained Delaunay triangulation. High-quality orthogonal unstructured grids are produced with good convergence properties for reservoir simulation.