Abstract: 3D seismic classification is a breakthrough technology to determine the three-dimensional distribution of pore fluid, lithology, and faults/fractures from multiple seismic attribute volumes. This method provides an innovative, timesaving solution for identification and definition of drilling targets, especially in areas with multiple pay zones and complex geology.

Abstract: Methods and systems for reservoir targeting, the systems implementing methods comprising filtering a plurality of values in a three-dimensional model to eliminate values which are below a threshold to create a filtered three-dimensional model; developing a first matrix from the filtered three-dimensional model representing a two-dimensional model of the reservoir, wherein the first matrix includes a plurality of cell center locations, cell areas, and the plurality of values; developing a second matrix from the first matrix using a distance-weighted sum of the plurality of values; and selecting target locations from the second matrix based on the distance-weighted sum of the plurality of values.

Abstract: A method producing full field radial grid includes both aerial and vertical gridding to divide a reservoir structure into simulation grid cells. The aerial gridding is performed by 1) specifying a reservoir boundary (including faults) and well locations; 2) distributing a set of concentric circles around each well location; 3) determining the circle-circle and circle-boundary intersection locations of these circles; 4) forming the aerial grid by selecting circles, arc segments of intersecting circles and radial lines which connect the ends of these arc segments to the corresponding well center; 5) and forming additional grid lines by selecting the connecting lines of two wells if their circles intersect, adding additional radial lines to certain wells, and connecting end points of certain selected arc segments. The vertical gridding is performed by casting the aerial grid vertically downwardly through all the layers defined in the reservoir structure.

Abstract: A method of managing oil fields include installing oil field sensors, coupling them to a local CPU having memory, programming the CPU for data collection and data analysis, and coupling local oil field CPUs to a web server. Human experts are granted access to oil field data in real time via the Internet. The local CPUs provide different levels of data to the web server. The web server provides the option to view raw data, partially analyzed data, or fully analyzed data. The local CPUs are programmed with parameters for analyzing the data and automatically determining the presence of anomalies. Upon detecting the occurrence of an anomaly, the local CPUs are programmed to notify one or more human experts by email, pager, telephone, etc. If no human expert responds to the notification within a programmed period of time, the local CPU automatically takes a programmed corrective action.

Abstract: A method of evaluating the capillary pressure curve of rocks of an underground reservoir from measurements on rock debris or fragments such as cuttings from the reservoir, over the total saturation range of these rocks, within a short period and at a low cost, from these measurements is disclosed. The method comprises measuring the permeability k of the debris, measuring the capillary pressure curve Pc as a function of the saturation of these fragments initially saturated with a fluid (brine for example) by subjecting them to centrifugation, and parametrizing a capillary pressure curve Pc satisfying empirical relations depending on adjustable parameters, constrained to adjust to an asymptotic part of the capillary curve measured by centrifugation, and to the value of permeability k measured on the cuttings, so as to obtain the whole of the capillary pressure curve. Applications include hydrocarbon reservoir evaluation.

Abstract: A method for determining a property of fluids in formations surrounding an earth borehole includes the following steps: producing, from measurements on a multiplicity of fluid samples, a database of stored fluid property training values related to stored fluid measurement training values; deriving, from the database, radial basis function parameters; deriving formation fluid measurement values; and determining, using radial basis function interpolation, the property of formation fluids from values in the database, the parameters, and the derived formation fluid measurement values.

Abstract: A method for providing production optimization of reservoir completions having a plurality of completed intervals via available production analysis and production logging data provides a quantitative analysis procedure for reservoir and fracture properties of a commingled reservoir system, that includes the steps of measuring pressure for specific zones in a reservoir; selecting a pressure traverse model; computing midzone pressures using the traverse model; comparing the computed midzone pressures with the measured pressures; and modeling the bottomhole pressure of the reservoir based on the traverse model.

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: An overall petroleum reservoir production optimization methodology permits the identification and remediation of unstimulated, under-stimulated, or simply poorly performing reservoir completed intervals in a multilayer commingled reservoir that can be recompleted using any of various recompletion methods (including but not limited to hydraulic fracturing, acidization, re-perforation, or drilling of one or more lateral drain holes) to improve the productivity of the well. This provides an excellent reservoir management tool and includes the overall analysis and remediation methodology that has been developed for commingled reservoirs. The specialized recompletion techniques can be used to improve the productivity of previously completed individual reservoir intervals in a commingled reservoir.

Abstract: A method for optimizing the production of oil reservoirs, and notably the production schemes, while taking into account uncertainties inherent in any reservoir survey. The method sequentially has the following stages: Stage 1: A sensitivity study to evaluate the impact, on the production of the oil reservoir, of the production scheme configurations tested (several well sites, . . . ) in relation to the uncertainties specific to the reservoir (permeability, aquifer force, . . . ). Stage 2: A quantification study of the risks associated with the configurations being studied to determine whether it is necessary to seek an optimum production scheme. Stage 4: A production scheme optimization study: having, the goal to determine the ideal production configuration for a given objective.

Abstract: A before-closure pressure-transient leakoff analysis for a fracture-injection/falloff test is used to mitigate the detrimental effects of pressure-dependent fluid properties on the evaluation of physical parameters of a reservoir. A fracture-injection/falloff test consists of an injection of liquid, gas, or a combination (foam, emulsion, etc.) containing desirable additives for compatibility with the formation at an injection pressure exceeding the formation fracture pressure followed by a shut-in period. The pressure falloff during the shut-in period is measured and analyzed to determine permeability and fracture-face resistance by preparing a specialized Cartesian graph from the shut-in data using adjusted pseudodata such as adjusted pseudopressure data and time as variables in a first method, and adjusted pseudopressure and adjusted pseudotime data as variables in a second method.

Abstract: The present invention relates to a method of locating oil and gas exploration prospects. A digital model of each of the many geologic strata that compose a basin is created for all or a portion of a basin by digitizing well log data 100, collecting all digitized well log data in a data base, marking common geological time markers throughout the entire basin and visually displaying the basin in a number of useful views 380, 580 to permit the isolation or identification of oil and gas producing geological formations. This allows for the generation of oil and gas drilling prospects 600 through the extrapolation of productive depositional features into un-drilled portions of the basin. The present invention expedites these processes and allows the available well log data to be viewed in ways not previously possible thereby greatly enabling oil and gas exploration and development in a basin.

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 closed-loop circulating system for drilling wells has control of the flow rates in and out of the wellbore. Kicks and fluid losses are quickly controlled by adjusting the backpressure. Kick tolerance and tripping margins are eliminated by real-time determination of pore and fracture pressure. The system can incorporate a rotating BOP and can be used with underbalanced drilling.

Abstract: Explicit depth extrapolation operators are constructed with variable operator lengths depending on maximum dip angle, accuracy condition, and wavenumber. Operator tables are then constructed using the explicit depth extrapolation operators. In a further embodiment, depth migration is performed using the explicit depth extrapolation operators from the operator tables.

Abstract: A method for determining a parameter of interest of a formation fluid, comprises moving a tool attached to a tubular member along a borehole in a subterranean formation. The tool is used to determine a formation fluid pressure and a formation fluid temperature at predetermined locations along the borehole and calculating a formation fluid density along the borehole therefrom. A density of a reference fluid is determined along the borehole and is related to the formation fluid pressure and the formation fluid temperature. The parameter of interest of the formation fluid is determined at a predetermined location from a comparison of the corresponding formation fluid density and the reference fluid density at the predetermined location.

Abstract: An inverse analysis method for characterizing diffusion of vapor from an underground source of volatile contaminant using data taken by an in-situ sensor. The method uses one-dimensional solutions to the diffusion equation in Cartesian, cylindrical, or spherical coordinates for isotropic and homogenous media. If the effective vapor diffusion coefficient is known, then the distance from the source to the in-situ sensor can be estimated by comparing the shape of the predicted time-dependent vapor concentration response curve to the measured response curve. Alternatively, if the source distance is known, then the effective vapor diffusion coefficient can be estimated using the same inverse analysis method. A triangulation technique can be used with multiple sensors to locate the source in two or three dimensions. The in-situ sensor can contain one or more chemiresistor elements housed in a waterproof enclosure with a gas permeable membrane.

Abstract: A set of seismic trace data is collected in an input data set that is first Fourier transformed in its entirety into the frequency domain. A normalized wavefield is obtained for each trace of the input data set in the frequency domain. Normalization is done with respect to the frequency response of a reference trace selected from the set of seismic trace data. The normalized wavefield is source independent, complex, and dimensionless. The normalized wavefield is shown to be uniquely defined as the normalized impulse response, provided that a certain condition is met for the source. This property allows construction of the inversion algorithm disclosed herein, without any source or source coupling information. The algorithm minimizes the error between data normalized wavefield and the model normalized wavefield. The methodology is applicable to any 3-D seismic problem, and damping may be easily included in the process.

Abstract: A method and system is disclosed for communicating information from a downhole location to the surface including a plurality of releasable vessels containing predetermined signal information affixed to the vessels prior to placement of the vessels downhole and indicative of the presence of at least one of three or more predetermined downhole conditions and a sensing and releasing system that senses the occurrence of the downhole condition, such as a simple threshold, and release the vessels in response to the sensing. The predetermined downhole condition can be characteristic of the fluid being produced in the borehole, such as water fraction, a certain level of mechanical wear or damage to downhole equipment such as bit wear, or the firing a one or more charges on a wireline deployed perforation tool.

Abstract: Method using <<Black Oil>> type modelling for predicting, as a function of time, the detailed composition of fluids produced by an underground reservoir under production, combined with a delumping stage allowing detailed thermodynamic representation of the reservoir fluids. The input data entered for the model are the thermodynamic parameters of the fluids such as viscosity, volume factor, density, gas-oil dissolution ratio, etc. (in form of charts, and/or by correlation, as a function of the pressure, of the temperature if it varies) and, if need be, an additional parameter keeping a memory of the composition of the gas such as, for example, the density of the gas), as well as data relative to the variations, as a function of the same <<abscissas>>, of the phase parameters required for delumping, without the latter being used during the <<Black Oil>> simulation of the flows.

Abstract: A method of managing a fluid or gas reservoir is disclosed which assimilates diverse data having different acquisition time scales and spatial scales of coverage for iteratively producing a reservoir development plan that is used for optimizing an overall performance of a reservoir.

Abstract: The present invention provides methods of monitoring the injection of a fluid into a subterranean formation. The present invention also provides a method of fracturing a subterranean formation. All methods feature the use of a wavelet transform of data generated by the subterranean injection process.

Abstract: The invention is a method for automated management of hydrocarbon gathering systems. Measurement data is automatically collected from automated measurement and control devices that are located in a hydrocarbon production system The data that is collected is compared with data stored in a database. The comparison of data is used to automatically schedule tests of the plurality of automated measurement and control devices. The invention also automatically collects well test data, system balance data, and hydrocarbon composition data and uses the collected data to manage the hydrocarbon production and delivery process. The invention also automatically generates periodic grid reports concerning the status of the gathering system.

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 gas-oil-ratio 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 gas-oil-ratio, 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 gas-oil-ratio and a percent contamination.

Abstract: A method for predicting the state of a geological formation. The method may include generating a separation key effective to extract a first feature from a signal or signals corresponding to a first state and a second feature, distinct from the first feature, from a signal or signals corresponding to a second state. The separation key may list at least one feature operator and a weighting table. The at least one feature operator may expand a test signal collected from a geological formation of unknown state in at least one of frequency space and time space to generate a plurality of feature segments. A weighting table may weight the plurality of feature segments. The weighted plurality of feature segments may be superimposed to form a third feature. The geological formation may be classified as having one of the first state and second state based on the correspondence of the third feature to one of the first feature and second feature.

Abstract: A method for processing magnetotelluric signals to identify subterranean deposits is provided for. The methods comprise obtaining magnetotelluric data from an area of interest. The magnetotelluric data comprises the amplitude of magnetotelluric signals recorded over time at one or more defined locations in the area of interest. The data for each location then is filtered through a set of frequency filters. The frequency filters correspond to subterranean depths over a range of interest. Amplitude peaks in the filtered data then are identified and analyzed to determine a value correlated to the resistance of the earth at each frequency and location. The resistance values are indicative of the presence or absence of deposits at the corresponding subterranean depth.

Abstract: Signals from microseismic events are used to obtain a parameter of reservoir such as porosity, permeability or saturation.

Abstract: The invention relates to an object-oriented method for simulating a property of at least one fluid in a fluid-containing physical system in which the physical system is represented by a multiplicity of volumetric cells and a multiplicity of connections between cells. The method uses cell-group objects and connection-group objects in the simulation. The invention can optionally comprise additional objects such as an object containing the entire model of the simulation and another object containing a portion of the entire model.

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: A method for predicting the state of a geological formation. The method may include generating a separation key effective to extract a first feature from a signal or signals corresponding to a first state and a second feature, distinct from the first feature, from a signal or signals corresponding to a second state. The separation key may list at least one feature operator and a weighting table. The at least one feature operator may expand a test signal collected from a geological formation of unknown state in at least one of frequency space and time space to generate a plurality of feature segments. A weighting table may weight the plurality of feature segments. The weighted plurality of feature segments may be superimposed to form a third feature. The geological formation may be classified as having one of the first state and second state based on the correspondence of the third feature to one of the first feature and second feature.

Abstract: A control system and method for determining optimal fluid injection pressure is based upon a model of a growing hydrofracture due to waterflood injection pressure. This model is used to develop a control system optimizing the injection pressure by using a prescribed injection goal coupled with the historical times, pressures, and volume of injected fluid at a single well. In this control method, the historical data is used to derive two major flow components: the transitional component, where cumulative injection volume is scaled as the square root of time, and a steady-state breakthrough component, which scales linearly with respect to time. These components provide diagnostic information and allow for the prevention of rapid fracture growth and associated massive water break through that is an important part of a successful waterflood, thereby extending the life of both injection and associated production wells in waterflood secondary oil recovery operations.

Abstract: The present invention is directed to a method and system for determining parameters inside a subterranean formation. In accordance with the present invention, a plurality of wireless data sensors are injected into the pores or fractures of a subterranean formation. The data sensors includes sensors that record parameters such as temperature, pressure and certain time stamps. Either autonoumously or upon command from a data interrogator tool located down hole, the plurality of data sensors form a wireless ad hoc network and telemeter the recorded data back to the data interrogator tool, which in turn communicates the data to a microprocessor located at the surface. Based on these data, the spatial distribution of the sensors and formation parameters such as temperature and pressure at each data sensor inside the subterranean formation can be obtained.

Abstract: A method of determining the position and emission rate of at least one source of emanations into an intervening medium, which method comprises measuring the concentration of the emanations in the intervening medium at selected measurement locations to obtain observed data, and measuring the velocity of the intervening medium; postulating a dispersion model; postulating a source model containing source parameters, such as the position(s) of assumed source(s) and assumed emission rate(s); calculating with the dispersion model for a postulated source model the concentration that would arise at the measurement location(s) to obtain synthetic data for the postulated source model; comparing the synthetic data with the observed data to obtain the source model that gives the closest fit; and outputting the position and emission rate of the at least one source assumed in the source model that gives the closest fit.

Abstract: Determining the viscosity of a hydrocarbon reservoir fluid that is present in a formation layer traversed by a borehole, which method involves the steps of selecting a location in the formation layer; lowering in the borehole to the location a tool that has a central conduit having an inlet, means for displacing fluids through the central conduit, and an optical fluid analyzer; making an exclusive fluid communication 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-wavelength range multipled with the length of the short-wavelength 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 property; and obtaining the magnitude of the in-situ viscosity from the oil property using a relation that has been obtained by fitting a curve through

Abstract: A method and apparatus for designing, monitoring or evaluating the growth of a subterranean hydraulic fracturing procedure is disclosed. The method uses techniques of analysis that are both accurate and efficient in reducing computing resources needed to process data. A computer generated method of estimation is used to determine the dimensions and shape of the hydraulic fracture. The estimate facilitates subsequent changes in fracturing parameter selection and design to maximize well performance and production. A rigorous method of evaluation is disclosed for a multi-layered or laminated petroleum reservoir. Material balance of hydraulically pumped fluids and proppant is maintained. In addition, the energy balance between the hydraulic fracture tip and the surrounding reservoir host rock is conserved.

Abstract: The method for horizon binning for an area of interest entails merging an attribute file with a second horizon file, identifying an area of interest of the merged file, identifying a time range for a time horizon file or a depth range for a depth horizon file, to perform the analysis, proposing a theory that the identified area has a portion contiguous between a hydrocarbon and water-bearing area, binning the identified area of interest using a file with time or depth values, computing a calculated value for each bin, creating a plot of the computed value versus the first value for each bin, viewing the plot to ascertain if a magnitude shift corresponds to a fluid contact, using discontinuity of the water and hydrocarbon reservoir models to confirm the theory, and using the discontinuity to determine a boundary between the water and hydrocarbon reservoir model and the corresponding water and hydrocarbon reservoirs for an identified area.

Abstract: The present invention generally provides methods of geological analysis. The method includes collecting wellbore data from a well undergoing underbalanced drilling. The wellbore data is then correlated to a seismic data to predict geological properties away from the wellbore. In one embodiment, correlating the seismic data with the wellbore data involves converting the seismic data and the wellbore data to a one-dimensional numerical series, respectively. The two respective one-dimensional numerical series are compared to each other to produce a mathematical formulation relating the two series. In another embodiment, the wellbore data may be separated into different categories or classifications and individually compared to the seismic data. Preferably, the categories are compared to two or more variations of seismic data and their attributes to derive at unique “signatures” for the respective category. The signatures may then be used to produce “classification” maps of the wellbore data.

Abstract: A method is disclosed for modelling fluid flows in a fractured multilayer porous medium by accounting for the real geometry of the fracture network and the local exchanges between the porous matrix and the fractures at each node of the network, thus allowing simulation of the interactions between the pressure and flow rate variations in a well running across the medium. The method essentially comprises discretizing the fractured medium by means of a mesh pattern, with fracture meshes centered on nodes at the various intersections of the fractures with each node being associated with a matrix volume, and determination of the flows between each fracture mesh and the associated matrix volume in a pseudosteady state. The method can be applied in hydrocarbon production well testing.

Abstract: A method for evaluating well performance includes deriving a reservoir effective permeability estimate from data points in a production history, wherein the data points include dimensional flow rates and dimensional cumulative production, at least one of the data points has no sand face flowing pressure information; and deriving at least one reservoir property from the reservoir effective permeability estimate and the data points according to a well type and a boundary condition for a well that produced the production data.

Abstract: A well optimization index WOI is an indicator for tracking trends and monitoring overall well performance. The WOI is a weighted average of two numbers reflecting operation execution performance (i.e., the Well Operation Time Ratio (WCTR)) and production result performance (i.e., the Productivity Index Ratio (PIR)). The WOI is calculated by a spreadsheet program used in a data-processing system. The spreadsheet program automatically generates the WOI for the well according to the expression: WOI = PI R ⁢ N + WCT R N + 1 ; wherein N is a weighting constant which represents a recovery of cost, that is estimated based on historical data.

Abstract: A method for optimizing the production of oil reservoirs, and notably the production schemes, while taking into account uncertainties inherent in any reservoir survey.

Abstract: A real-time method is disclosed for maintaining subterranean formation stability through monitoring the interaction between the formation and fluids introduced into (or produced from) a wellbore penetrating the formation. The method employs real-time wellbore (in)stability logging methodology. The method is exemplified by a Pore Pressure Transmission (PPT) test. In such test, test fluids are exposed to Pierre II shales (20% w/w NaCl solution and sodium silicate fluid with 20% w/w NaCl, for example) in a PPT apparatus. Membrane efficiency of the two fluids when exposed to the outcrop shale is calculated, and based on the simultaneous acquisition of acoustic data, estimation of a dynamic rock property is made.

Abstract: A single intranet, internet, or World Wide Web-accessible interface is provided for, initiation of, interactive adjustments to, and access to the outputs of an integrated workflow of a plurality of analytical computer applications for characterization and analysis of traits and optimal management of the extraction of oil, gas, and water from a subsurface reservoir. By combining disparate analytical application tools in a seamless and remotely accessible, package, incompatibility problems caused by the disparate nature of petroleum analysis methods is reduced. The assumptions, analytic processes, and input data used for one analysis may be readily retrieved and re-evaluated for that reservoir or for future evaluations of the same or other reservoirs. Thus a flexible database of analysis tools and data may be implemented for access, input, and output of workflow and analytical data in the field, in conjunction with standard main computer servers, software and plug-ins, and portable remote computers.

Abstract: A multi-scale finite-volume (MSFV) method to solve elliptic problems with a plurality of spatial scales arising from single or multi-phase flows in porous media is provided. Two sets of locally computed basis functions are employed. A first set of basis functions captures the small-scale heterogeneity of the underlying permeability field, and it is computed to construct the effective coarse-scale transmissibilities. A second set of basis functions is required to construct a conservative fine-scale velocity field. The method efficiently captures the effects of small scales on a coarse grid, is conservative, and treats tensor permeabilities correctly. The underlying idea is to construct transmissibilities that capture the local properties of a differential operator. This leads to a multi-point discretization scheme for a finite-volume solution algorithm. Transmissibilities for the MSFV method are preferably constructed only once as a preprocessing step and can be computed locally.

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 method for displaying a borehole trajectory includes displaying the borehole trajectory and an indicator of a working interval in a big view window; and displaying a section of the borehole trajectory in a small view window, wherein the section corresponds to the working interval. The method may further includes displaying well log data in a log view window. A system for displaying a borehole trajectory includes a display; and a computer operatively coupled to the display, the computer having a program to display the borehole trajectory on the display, the program comprising instructions to enable: displaying the borehole trajectory and an indicator of a working interval in a big view window; and displaying a section of the borehole trajectory in a small view window, wherein the section corresponds to the working interval.

Abstract: Loading of one fluid control device with respect to other fluid control devices in a fluid system is evaluated by a Dynamic Relative Load Rate [DRLR] variable that is common to each devices. DRLR methods compare the relative performances of multiple fluid control devices, such as strings of gas-lift valves that lift hydrocarbons in a well-field. The dimensions of a DRLR variable are a combination of the dimensions of fluid pressure, flow rate, temperature, mass, length, and/or time test data. Evaluating graphs of DRLR data shows that the conventional measure of a gas-lift-valve-bellows load rate, kPa/cm (psi/inch) is only one member of a set of relative load-performance measures, including kPa/sec (psi/sec), that describe the loading-sensitivity of fluid control devices. Test data are generated quickly and cost effectively by a Fluid Energy Pulse Test System with improvements.

Abstract: The present invention generally provides methods of geological analysis. The method includes collecting wellbore data from a well undergoing underbalanced drilling. The wellbore data is then correlated to a seismic data to predict geological properties away from the wellbore. In one embodiment, correlating the seismic data with the wellbore data involves converting the seismic data and the wellbore data to a one-dimensional numerical series, respectively. The two respective one-dimensional numerical series are compared to each other to produce a mathematical formulation relating the two series. In another embodiment, the wellbore data may be separated into different categories or classifications and individually compared to the seismic data. Preferably, the categories are compared to two or more variations of seismic data and their attributes to derive at unique “signatures” for the respective category.

Abstract: A method for predicting reservoir properties at an unexplored subterranean location based on known seismic attributes at the unexplored subterranean location, as well as known reservoir properties and seismic attributes at a plurality of explored subterranean locations proximate to the unexplored subterranean locations. The method uses residual stepwise regression to generate a prediction equation capable of calculating predicted reservoir properties based on multiple seismic attributes. The residual stepwise regression involves using residual values from a previous regression step to determine which seismic attribute will be included in a subsequent regression step.

Abstract: A method for predicting reservoir properties at an unexplored subterranean location based on known seismic attributes at the unexplored subterranean location, as well as known reservoir properties and seismic attributes at a plurality of explored subterranean locations proximate to the unexplored subterranean locations. The method uses residual stepwise regression to generate a prediction equation capable of calculating predicted reservoir properties based on multiple seismic attributes. The residual stepwise regression involves using residual values from a previous regression step to determine which seismic attribute will be included in a subsequent regression step.