Abstract: 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, “&egr;x,y,z” (the ‘x,y,z elongation strains’) and “&ggr;xy,yz,zx” (the ‘shear strains’) are determined since “&egr;x,y,z” and “&ggr;xy,yz,zx” are function of “u”, “v”, and “w” When “&egr;x,y,z” and “&ggr;xy,yz,zx” are determined, “&sgr;x,y,z” (the ‘elastic normal rock stress in x,y,z directions’) and “&tgr;xy,yz,xz” (the ‘elastic shear stress’) are determined since “&sgr;x,y,z” and “&tgr;xy,yz,xz” are a function of “&egr;x,y,z” and “&ggr;xy,yz,zx”.

Abstract: A seismic signal is represented as a combination of a geologic signal and a noise signal. The representation of the seismic signal is decomposed into a linear combination of orthonormal components. One or more components are identified in which the geologic signal and the noise signal are uncorrelated. The noise signal is expanded as a product of an unknown noise amplitude modulation signal and a known noise spatial periodicity signal at the identified components. The expansion is solved for an estimate of the noise amplitude modulation signal at the identified components. The noise signal is estimated by multiplying the estimated noise amplitude modulation signal by the noise spatial periodicity signal. The estimated noise signal can be removed from the seismic signal to generate an estimate of the geologic signal.

Abstract: Methods and devices for determining the quality of an oil well reserve or the like delivering a given fluid derived from a productive layer, by measuring the response R of the well. The method implemented by the device comprises modulating the fluid flow rate (4) in the well (1) by a sinusoidal function with a controllable preventer (5), and measuring the variations in flow rate and pressure of the fluid respectively with a flow meter (7) and a pressure sensor (9), the response Rc of the well (1); if the productive layer comprises a damaged zone having a positive formation damage of non-null thickness, is obtained by the equation (I), and the response Rf of the well; if the productive layer comprises a fracture having a negative formation damage, is obtained by the equation (II). The invention is applicable to oil prospecting.

Abstract: A method for determining properties of a formation fluid including obtaining data related to an optical density at a methane peak and an optical density at an oil peak for a fluid sample at a plurality of times, calculating an apparent gasoilratio of the sample fluid from the optical density of the fluid sample at the methane peak to the optical density of the fluid sample at the oil peak at each of the plurality of times based on the data, selecting a power function of a sampling parameter for a buildup of the apparent gasoilratio, calculating an exponential constant of the power function based on the data, and determining at least one selected from the group consisting of a contamination free gasoilratio and a percent contamination.

Abstract: The present invention is a method for using petrophysical data from a plurality of wells, in a plurality of reservoir regions, containing a plurality of reservoir rock types, in the context of a three-dimensional geological model, for identifying dimensionless capillary pressure functions and using these dimensionless capillary pressure functions for determining reservoir fluid volumes, fluid contacts, the extent of reservoir compartmentalization, and an improved estimate of reservoir permeability. The present invention is directed to the method and finished product of same.

Abstract: A method for computing complexity, confidence and technical maturity indices for the evaluation of a reservoir is disclosed. The method comprising the steps of (a) making estimates of reservoir components which are associated with a subsurface reservoir evaluation; (b) making estimates of confidence values for the estimates of the reservoir components; and (c) computing an evaluation index for the evaluation of the reservoir based upon at least one of the estimates of the reservoir components and the estimates of the confidence values. Complexity and confidence scores are assigned to the respective estimates of the reservoir components and estimates of confidence values. These scores are combined to produce complexity and confidence indices. This evaluation tool is intended to help improve the assessment of the reliability of probabilistic reservoir production forecasts. The tool provides an indicator of the reliability of the forecast production profiles and reserves estimations.

Abstract: 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, “&egr;x,y,z” (the ‘x,y,z elongation strains’) and “&ggr;xy,yz,zx” (the ‘shear strains’) are determined since “&egr;x,y,z” and “&ggr;xy,yz,zx” are function of “u”, “v”, and “w”. When “&egr;x,y,z” and “&ggr;xy,yz,zx” are determined, “&sgr;x,y,z” (the ‘elastic normal rock stress in x,y,z directions’) and “&tgr;xy,yz,zx” (the ‘elastic shear stress’) are determined since “&sgr;x,y,z” and “&tgr;xy,yz,xz” are a function of “&egr;x,y,z” and “&ggr;xy,yz,zx”.

Abstract: A neural network based system, method, and process for the automated delineation of spatially dependent objects is disclosed. The method is applicable to objects such as hydrocarbon accumulations, aeromagnetic profiles, astronomical clusters, weather clusters, objects from radar, sonar, seismic and infrared returns, etc. One of the novelties in the present invention is that the method can be utilized whether or not known data is available to provide traditional training sets. The output consists of a classification of the input data into clearly delineated accumulations, clusters, objects, etc. that have various types and properties. A preferred but non-exclusive application of the present invention is the automated delineation of hydrocarbon accumulations and sub-regions within the accumulations with various properties, in an oil and gas field, prior to the commencement of drilling operations. The invention may also be used to increase the effectiveness of enhanced oil recovery techniques.

Abstract: A process of designing a screenless completion for an oil or gas well includes selecting an oil or gas well having known characteristics and inputting data about them into a computer; determining, through operation of the computer, whether a screenless completion should be performed on the selected well and, if so, identifying materials to be used in the screenless completion and in response indicating to a user a screenless completion design using the identified materials. Different types of screenless completion designs are made available. These steps can be performed for multiple wells, preferably with similar results for similar wells.

Abstract: A system for measuring density of material which can be embodied to measuring bulk density of material penetrated by a borehole. The probe component of the system comprises a source of neutron radiation and preferably two gamma ray spectrometers. The neutron source induces gamma radiation with energies up to about 10 MeV within the material being measured. Formation bulk density is determined by combining spectra of the induced gamma radiation with preferably two gamma ray spectrometers at differing axial spacings from the source. The high energy and dispersed nature of the induced gamma radiation yields greater radial depth of investigation than that obtainable with prior art backscatter density systems, which typically use gamma ray sources local to a probe and of energy about 1.3 MeV or less. The system can alternately be embodied to measure other material properties and to measure density of materials not penetrated by a borehole.

Abstract: The present invention provides a method and apparatus for remotely analyzing and affirmatively notifying appropriate personnel of problems and events associated with an oil recovery system-comprising hundreds of oil rigs over a vast geographic area. The results of selected Health Checks, which are run on each oilrig, are reported to a central server. The central server populates a data base for the oil recovery system, displays a red/yellow/green color coded electronic notification and status for an entire oil recovery system and affirmatively alerts appropriate personnel of actions required to address events associated with an oilrig in an oil recovery system. The diagnostics run at each oilrig are configurable at the individual rig. The present invention provides a dynamic oilrig status reporting protocol that enables population and display of a tree node structure representing an entire oil recovery system status on a single screen at a top level.

Abstract: An apparatus and method for providing an end-user operator with the ability to assign temporary control of a set of one or more operator-specified instrument control operations to one, single-action switch on a signal measurement system front panel. The assigned instrument control operations are preferably represented by text strings in a macro text file that is developed and modified with the use of a text editor integrated into or operatively coupled with the signal measurement system.

Abstract: A system for investigating subterranean strata. An electromagnetic field is applied using a fixed dipole antenna transmitter and this is detected using a dipole antenna receiver. The receiver is moved from one location to another in dependence upon the strength of the detected signal.

Abstract: This invention relates to methods for calibrating a formation permeability model with respect to data obtained from fluid flow measurements. A method according to the invention includes determining a correlation coefficient for a porosity-irreducible water saturation relationship; determining a leading coefficient for a formation permeability model; and determining at least one exponent parameter for the formation permeability model by minimizing a basis function that represents a difference between a formation permeability estimate derived from the formation permeability model and a formation permeability estimate derived from the fluid flow measurements.

Abstract: A reservoir in payrock in analysed using finite element simulation. A reservoir engineer selects an appropriate model from a set of template models, each including a set of polygons in plan and layers in elevation. The polygons are defined in objects instantiated from classes by control points and the layers as depth values of control points. A pattern object sweeps rotationally about a wellbore in a wellbore polygon to define a pattern of elements, fewer in number with distance from the wellbore. A polygon object also sweeps linearly from a generator line in the direction of a base line. The generator and base lines correspond to polygon boundaries. Finite element simulation is performed with the model so derived.

Abstract: A method of determining fluid flow in a volume containing two or more fluid components, comprising determining a pressure field for the volume. One or more streamlines are determined from the pressure field, and the fluid composition is solved for the fluid composition along the or each streamline. The pressure may also be solved along the or each streamline. The step of solving along the or each streamline may be performed using a finite difference technique.

Abstract: In accordance with an embodiment of the present invention, a method of processing large volumes of data to allow for real-time reservoir management is disclosed, comprising: a) acquiring a first data series from a first reservoir sensor; b) establishing a set of criteria based on reservoir management objectives, sensor characteristics, sensor location, nature of the reservoir, and data storage optimization, etc.; c) identifying one or more subsets of the first data series meeting at least one of the criteria; and optionally d) generating one or more second data series based on at least one of the subsets. This methodology may be repeated for numerous reservoir sensors. This methodology allows for intelligent evaluation of sensor data by using carefully established criteria to intelligently select one or more subsets of data. In an alternative embodiment, sensor data from one or more sensors may be evaluated while processing data from a different sensor.

Abstract: The invention is a method for removing trapped water bottom multiples, receiver side peg-leg multiples, and source side peg-leg multiples from dual sensor OBC data, where the data includes both pressure signals and velocity signals. The pressure and velocity signals are compared to determine any polarity reversals between them. Polarity reversals are used to identify and separate up-going and down-going wavefields in the pressure and velocity signals. A matching filter is applied to a portion of the velocity signal where polarity reversals exist. The down-going wavefield is then estimated by calculating the difference between the portion of the velocity signal where polarity reversals exist and the portion of the pressure signal where polarity reversals exist and applying a scaling factor to the result. An attenuated up-going pressure wavefield is then determined by combining the estimated down-going wavefield and the pressure signal.

Abstract: A simulation method makes a noise analysis based on parameters including a conductor resistance which takes skin effect into consideration. The simulation method calculates a first resistance of one of conductors having a largest cross sectional area, obtains a predetermined pitch which saturates a diagonal component of a second resistance of a conductor with reference to the first resistance and makes the diagonal component approximately constant, by varying a pitch of the conductors, calculates the parameters for each pitch with respect to one of the pitches larger than or equal to the predetermined pitch and the pitches smaller than the predetermined pitch, and substitutes the parameters calculated for the one of the pitches with respect to the other of the pitches, and outputs calculation results.

Abstract: A method for obtaining, by means of an inversion process, an optimum model of a physical characteristic in a heterogeneous medium (the impedance of an underground zone in relation to waves transmitted in the ground for example), by taking as the starting point an a priori model of the physical characterized that is optimized by minimizing a cost function dependent on differences between the optimized model which is sought and the known data, considering the a priori model. Construction of the a priori model comprises correlation by kriging between values of the physical quantity known at different points of the medium along discontinuities (strata directions). Uncertainties about the values of the physical quantity in the a priori model in relation to the corresponding values in the medium follow a covariance model that controls the inversion parameters more quantitatively. The characteristics of the covariance model are defined in connection with the structure of the data observed or measured in the medium.

Abstract: A neural network based system, method, and process for the automated delineation of spatially dependent objects is disclosed. The method is applicable to objects such as hydrocarbon accumulations, aeromagnetic profiles, astronomical clusters, weather clusters, objects from radar, sonar, seismic and infrared returns, etc. One of the novelties in the present invention is that the method can be utilized whether or not known data is available to provide traditional training sets. The output consists of a classification of the input data into clearly delineated accumulations, clusters, objects, etc. that have various types and properties. A preferred but non-exclusive application of the present invention is the automated delineation of hydrocarbon accumulations and sub-regions within the accumulations with various properties, in an oil and gas field, prior to the commencement of drilling operations. The invention may also be used to increase the effectiveness of enhanced oil recovery techniques.

Abstract: Deteriming the viscosity of a hydrocarbon reservoir fluid that is present in a formation layer traversed by a borehole, which method comprises the steps of selecting a location in the formation layer; lowering in the borehole to the location a tool that comprises a central conduit having an inlet, means for displacing fluids through the central conduit, and an optical fluid analyser; making an exclusive fluid commuication between the formation and the inlet of the central conduit; obtaining a spectrum of the optical density; calculating a first factor that is the maximum optical density in a predetermined short-wavelenght range multiplied with the length of the short-wavelenght range, calculating a second factor which is the integral over the same short-wavelength range of the spectrum, subtracting the second factor from the first factor to obtain a hydrocarbon oil porperty; and obtaining the magnitude of the in situ viscosity from the oil property using a relation that had been obtained by fitting a curve (1

Abstract: A fiber optic sensor system provides sufficient thermal information to determine the mass flow rates of produced fluids within a well bore, using an optical fiber placed within or adjacent to the well bore without interference with production or prejudicing the integrity of the well. Mass flow rates of fluid in a conduit (20) located in a heat sink differing in temperature from the fluid are determined by obtaining a distributed temperature profile (32) of fluid flowing along a length of conduit (15) by using optical data obtained from a length of optical fiber in thermal contact therewith, obtaining a profile of the heat sink temperature external to the conduit, and deriving mass flow rates of fluids in the conduit from the said profiles and from measured thermal transfer parameters.

Abstract: Method of predicting paraffin deposition risks during hydrocarbon production and/or transport, applicable at an early reservoir characterization and production stage. It comprises forming a database characterizing the hydrocarbons in the formation, including density data acquired by well logging and data obtained by analysis of rock samples taken from the reservoir formation, an analytical representation of the hydrocarbons by a limited number of pseudo-components comprising each certain hydrocarbon classes with a definition of their respective mass fractions and application of data of said base to a thermodynamic model for determining one or more parameters indicative of the crystallization conditions such as, for example, the starting crystallization temperature, the solid fraction that precipitates when the temperatures falls below this starting crystallization temperature, etc. Applications: hydrocarbon production field valuation.

Abstract: A neural network based system, method, and process for the automated delineation of spatially dependent objects is disclosed. The method is applicable to objects such as hydrocarbon accumulations, aeromagnetic profiles, astronomical clusters, weather clusters, objects from radar, sonar, seismic and infrared returns, etc. One of the novelties in the present invention is that the method can be utilized whether or not known data is available to provide traditional training sets. The output consists of a classification of the input data into clearly delineated accumulations, clusters, objects, etc. that have various types and properties. A preferred but non-exclusive application of the present invention is the automated delineation of hydrocarbon accumulations and sub-regions within the accumulations with various properties, in an oil and gas field, prior to the commencement of drilling operations. The invention may also be used to increase the effectiveness of enhanced oil recovery techniques.

Abstract: A subsurface formation petrophysical evaluation method including: determining formation porosity and permeability using a quantitative indication of formation composition; estimating water-filled formation resistivity using the formation porosity; associating differences between measured formation resistivity and estimated water saturated formation resistivity with the presence of subsurface hydrocarbons; and estimating irreducible formation water saturation using the formation porosity and the formation permeability. The invention further involves an apparatus adapted to carry out the inventive method.

Abstract: 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, “&egr;x,y,z” (the X,Y,Z elongation strains) and “&ggr;xy,yz,zx” (the shear strains) are determined since “&egr;x,y,z” and “&ggr;xy,yz,zx” are function of “u”, “v”, and “w”. When “&egr;x,y,z” and “&ggr;xy,yz,zx” are determined. “&sgr;x,y,z” (the elastic normal rock stress in x,y,z directions) and “&tgr;xy,yz,xz” (the elastic shear stress) are determined since “&sgr;x,y,z” and “&tgr;xy,yz,xz” are a function of “&egr;x,y,z” and “&ggr;xy,yz,zx”.

Abstract: System and methods for creating a visual interpretation of the amount of flow between injection and production wells in a hydrocarbon field at any instant in time. Using conventional reservoir simulation input, streamlines are first generated using a streamline-based flow simulator. The streamlines are then used to determine well pairs and the volumetric flow rate associated with each well in the pair. The fraction of the flow rates in the well pair to the total flow rates of each well are then calculated. These fractions are also known as well allocation factors. After placing the well locations on a multi-dimensional map, the well allocation factors are represented by a multi-dimensional, multi-color stick map connecting each well pair.

Abstract: The invention concerns a method comprising experimentally determining the variation curve of capillary pressure in pores on the basis of saturation with respect to liquid phases, modelling the pores of the porous environment by capillary distribution with fractal distribution while taking into account in the case of a three-phase water (wetting fluid)-oil-gas mixture for example stratification of the constituents inside the pores, with water in contact with the walls, gas in the centre and oil forming an intervening layer, determining, on the basis of said capillary pressure curve, values of fractal dimension corresponding to a series of given values of saturation relative to the liquid phase, modelling hysteresis effects modifying the mobile saturation levels of fluids actually displaced in the sample which vary in the course of drainage and imbibition cycles, modelling relative permeability levels directly in the form of analytical expressions depending on the different values of fractal dimension obtained

Abstract: A method for detection and monitoring of hydrocarbon deposits by measuring infrasonic spectral characteristics of microseismic noise of the earth. The method is used onshore and offshore for detection of hydrocarbon deposits and for monitoring of producing oil and gas fields and subsurface storage of natural gas. In one method of the invention, at least one receiver of seismic vibrations capable of recording vibrations in the infrasonic range is placed over an area being surveyed. The spectral characteristics of the microseismic noise of the earth recorded within a 2 to 5 Hz frequency range are used as a “passive” information signal. A hydrocarbon deposit is determined by the presence of a spectral anomaly on a spectrum of the passive information signal relative to a spectrum of an information signal from the area known not to contain hydrocarbons.

Abstract: An invention for the filtering, sorting and analysis of microseismicity induced during production of fluid resources from their reservoirs which allows direct 4 dimensional measurements of all or many of the components of the permeability field as well as other petrophysical rock properties important to reservoir analysis and monitoring. The seismicity associated with the permeability field is identified by its spatial and temporal location in two general conoidal volumes, symmetrically disposed about the injection point in any well being used for this purpose (FIG. 1). The cone axes are parallel to the maximum compressive stress directions of the ambient stress field. Increasing fluid pressure causes seismicity to rapidly migrate outward from the injection points (FIG. 2). The seismicity moves at rates that are order of magnitudes greater than that of D'arcyian flow and covering distances measured in kilometers.

Abstract: Method for forming, by means of an inversion technique, a model of an underground zone, constrained by static data: data obtained by seismic exploration or measured in situ (logs), and by dynamic data: production measurement, well testing, etc. From an a priori selected meshed geologic model and from relations between parameters or physical quantities characteristic of the medium: acoustic impedance and cabsolute permeability for example, a simultaneous inversion of the two parameters is performed by minimizing a global cost function, which has the effect of considerably decreasing the number of possible solutions and of improving characterization of the underground zone. The method can be used notably for modelling hydrocarbon reservoirs, of zones likely to be used as gas, waste storage places, etc.

Abstract: A method of seismic investigation using the swept impact seismic technique involves measuring the response of a site to be investigated to a series of controlled impact sequences applied at different points of the site, each sequence using impacts generating pulses of energy at 100-2500 Hz., the impacts of the sequence having a repetition frequency swept between frequencies in the range of 10 to 500 Hz., the end frequencies having a ratio of at least 1.5 to 1, and the number of impacts in the sequence being at least 100 (and preferably at least 500). The invention also extends to apparatus for implementing such a method, comprising an electrically-actuated hammer having an impact frequency variable through a range of at least 1.5:1 within the range 10 to 500 Hz., and generating impacts characterized by substantial energy within a frequency range of 100-5000 Hz.

Abstract: A method for determining quality of lubricating oil includes positioning first and second electrodes in the oil, wherein the electrodes are coated with an electrically insulating material; applying a symmetrically balanced time-varying potential to the electrodes, the potential having a predetermined amplitude; sweeping the potential over a range of frequencies from a first frequency to a second frequency greater than the first frequency; monitoring magnitude of amplitude modulation of the potential over the range of frequencies; and determining the quality of the oil based on variation of the amplitude modulation. A system for practicing the method is also provided.

Abstract: A method of real time field wide reservoir management comprising the steps of processing collected field wide reservoir data in accordance with one or more predetermined algorithms to obtain a resultant desired field wide production/injection forecast, generating a signal to one or more individual well control devices instructing the device to increase or decrease flow through the well control device, transmitting the signal to the individual well control device, opening or closing the well control device in response to the signal to increase or decrease the production for one or more selected wells on a real time basis. The system for field wide reservoir management comprising a CPU for processing collected field wide reservoir data, generating a resultant desired field wide production/injection forecast and calculating a target production rate for one or more wells and one or more down hole production/injection control devices.

Abstract: A neural network based system, method, and process for the automated delineation of spatially dependent objects is disclosed. The method is applicable to objects such as hydrocarbon accumulations, aeromagnetic profiles, astronomical clusters, weather clusters, objects from radar, sonar, seismic and infrared returns, etc. One of the novelties in the present invention is that the method can be utilized whether or not known data is available to provide traditional training sets. The output consists of a classification of the input data into clearly delineated accumulations, clusters, objects, etc. that have various types and properties. A preferred but non-exclusive application of the present invention is the automated delineation of hydrocarbon accumulations and sub-regions within the accumulations with various properties, in an oil and gas field, prior to the commencement of drilling operations.

Abstract: A method for ascertaining a characteristic of a geological formation surrounding a wellbore. The method comprises first generating a set of data including azimuthal and radial information. A set of parameters indicative of fluid behavior in the formation is determined for each one of at least two azimuths from the generated data. A tool-specific invasion factor is then determined. The characteristic is then determined from the parameters, the azimuthal information, and the invasion factor.

Abstract: A system for producing a material balance solution for well patterns in a hydrocarbon reservoir is described that automatically optimizes the fluid allocation factors for each well used in determining the solution. The system automatically optimizes estimates for the allocation factors to be used in the material balance solution by randomly generating a first generation of allocation factor strings, each string in the generation assigning allocation factors to each of the wells in the reservoir. A fitness function value is determined for each of the strings by evaluating a fitness function, wherein the fitness function comprises the sum of the differences between computed and measured field pressures for each pattern, and the sum of the differences between target allocation factors and the allocation factors specified within the string for each well. A succeeding generation of allocation factor strings is produced according to a genetic algorithm.

Abstract: A Flogrid Simulation Gridding Program includes a Flogrid structured gridder. The structured gridder includes a structured areal gridder and a block gridder. The structured areal gridder will build an areal grid on an uppermost horizon of an earth formation by performing the following steps: (1) building a boundary enclosing one or more fault intersection lines on the horizon, and building a triangulation that absorbs the boundary and the faults; (2) building a vector field on the triangulation; (3) building a web of control lines and additional lines inside the boundary which have a direction that corresponds to the direction of the vector field on the triangulation, thereby producing an areal grid; and (4) post-processing the areal grid so that the control lines and additional lines are equi-spaced or smoothly distributed. The block gridder of the structured gridder will drop coordinate lines down from the nodes of the areal grid to complete the construction of a three dimensional structured grid.

Abstract: A method for detection of a disturbance in a waveguide comprising transmitting a wavefield having symmetric and antisymmetric components from a horizontally and/or vertically polarized source and/or pressure source disposed symmetrically with respect to the longitudinal central axis of the waveguide at one end of the waveguide, recording the horizontal and/or vertical component or a pressure of the wavefield with a vertical array of receivers disposed at the opposite end of the waveguide, separating the wavenumber transform of the wavefield into the symmetric and antisymmetric components, integrating the symmetric and antisymmetric components over a broad frequency range, and comparing the magnitude of the symmetric components and the antisymmetric components to an expected magnitude for the symmetric components and the antisymmetric components for a waveguide of uniform thickness and properties thereby determining whether or not a disturbance is present inside the waveguide.

Abstract: A petroleum reservoir production modeling apparatus and method is disclosed which incorporates a complete (from reservoir to wellhead) production systems analysis system for the evaluation of petroleum reservoir production performance, using industry accepted techniques of analysis. A computer generated model facilitates the determination of well and formation properties in a computerized methodology, efficiently, reliably and accurately, thereby facilitating subsequent changes in wellbore properties to maximize well production. The method includes a rigorous analytic reservoir inflow performance model for a variety of well types and reservoir outer boundary conditions and drainage area shapes, and uses industry accepted production analysis techniques. These techniques accepted in the industry include material balance, decline curve analysis, and non-linear minimization procedures. Field-recorded production data is evaluated to obtain estimates of the well or formation properties.

Abstract: An apparatus and method for the exploration of hydrocarbons by obtaining a set of seismic signal traces distributed over a pre-determined three-dimensional volume of the earth and using a computer to: divide the three-dimensional volume into a plurality of vertically stacked and generally spaced apart horizontal slices; divide each of the slices into a plurality of cells having portions of at least three seismic traces located therein; measure the cross-correlation between one pair of traces lying in one vertical plane to obtain an in-line value and the cross-correlation between another pair of traces lying in another vertical plane to obtain a cross-line value; and combine the in-line value and the cross-line value to obtain one coherency value for each of the cells; and display the coherency values.

Abstract: An integrated interpretation methodology is described that evaluates carbonate reservoirs. The methodology consists of first classifying the rock facies. A geometrical model specific to the classification is then used to predict the response of the rock to a variety of stimuli. A reconstruction of the geometrical model is made by comparing the measurements with the model predictions. The model is then used to predict the resistivity and the hydraulic transport properties of the rock, thereby enabling computation of both the reserves and their production behavior.

Abstract: A self-contained mobile repair unit for repairing wells includes the hydraulic and pneumatic tooling required to do a variety of jobs including the installation and removal of an inner pipe string, sucker rods and a pump. The repair unit, hydraulic tooling and pneumatic tooling share a common engine and a common process monitor. Access to data gathered by the monitor is restricted at the job site itself. Instead, the data is transmitted to a remote home base for the purpose of monitoring operations form a central location.

Abstract: A method is disclosed of predicting a characteristic of a fluid-containing physical system such as a reservoir. The physical system is discretized to a plurality of gridcells. For each gridcell, nonlinear governing equations are constructed that are representative of fluid properties for each fluid. The nonlinear terms are linearized to derive linear equations at a current timestep. The linear equations are then solved to determine estimates of the solution. The estimated solution is then improved by a gridcell-by-gridcell computation wherein flows into and out of a particular gridcell are determined using linearized values of nonlinear terms in gridcells adjacent that particular gridcell. The improved solution is used to predict a property of a fluid in the physical system at end of the timestep. These calculation steps are repeated for a plurality of timesteps and the results are used to predict a property of the physical system and the fluids it contains as a function of time.

Abstract: A method for obtaining a representation of the textures of a geological structure, characterized in that images characteristic of the sedimentology of the environment are formed, parameters corresponding to the nature of the images are estimated at every point of each image and in a spatial domain around the point so as to determine a texture vector for each of the points and to obtain a set of texture vectors. The method also includes the steps of selecting texture vectors representative of the characteristic textures of the geological environment in the set of texture vectors; and using a neural network formed of cells distributed in two dimensions which contains as many cells as characteristic textures. The selected texture vectors are used to submit the neural network to a learning process so that a final topology map of the textures characteristic of the geological environment is obtained.

Abstract: A method controlling development of an oil or gas reservoir uses a neural network and genetic algorithm program to define a neural network topology and the optimal inputs for that topology. The topology is defined from identified and selected (1) parameters associated with the formation or formations in which actual wells are drilled in the reservoir and (2) parameters associated with the drilling, completion and stimulation of those wells and (3) parameters associated with the oil or gas production from the wells. Subsequent drilling, completion and stimulation of the reservoir is determined and applied based on hypothetical alternatives input to the topology and resulting outputs.

Abstract: A method for generating a flow profile of a wellbore whereby a resistivity tool is run through the wellbore, while the wellbore is being drilled, to sequentially measure and record, at each of a sequence of selected points along the wellbore, a sequential series of resistivities measured while drilling (MWD). Fluid from the wellbore is then allowed to permeate into the formation. The resistivity tool is then run through the wellbore, after the drilling mud has permeated into the formation, to sequentially measure and record, at substantially the same points at which the MWD resistivity measurements were made, a sequential series of resistivities measured after drilling (MAD). For each point, the arithmetic difference between the MWD resistivity and the corresponding MAD resistivity recorded for the respective point is calculated.

Abstract: A Method for modeling, from an initial undeformed state, the evolution of a rock basin in the course of time taking into account a) the sliding along major tectonic discontinuities with internal deformation of sediments and at the same time b) mechanical compaction due to burial of sediments by tectonic deformation or sedimentation. After first subdividing the geological objects in the basin into a number of layers or banks by limits (stratigraphic discontinuities defining banks, faults defining imbricate structures, etc.) whose geometric positions are known, the banks are defining by grids. The tectonic deformation of each modeled layer is determined separately taking its thickness and length into account as far as possible, and the grids are modified to take into account the compaction associated with the degree to which the grid elements are buried. All the intermediate geometries of the evolution process are obtained incrementally.

Abstract: The present invention relates generally to the field of seismic exploration and, in more particular, to methods of quantifying and visualizing structural and stratigraphic features in three dimensions through the use of eigenvector and eigenvalue analyses of a similarity matrix. This invention also relates to the field of seismic attribute generation and the use of seismic attributes derived from similarity matrices to detect the conditions favorable for the origination, migration, accumulation, and presence of hydrocarbons in the subsurface. Additionally, the methods disclosed herein provide a new means for analyzing unstacked seismic data to uncover AVO effects. The invention disclosed herein will be most fully appreciated by those in the seismic interpretation and seismic processing arts.