Abstract: A method for virtual metering of fluid flow rates in a cluster of fluid injection wells which are connected to a collective fluid supply header conduit assembly comprises: a) sequentially testing each of the injection wells of the cluster by closing in that well and then performing a dynamically disturbed injection well test (DDIT) on the tested well, during which test the injection rate to the tested well is varied over a range of flows whilst the fluid flowrate in the header conduit assembly and one or more injection well variables, including tubing head pressure, of the well under test and of the other wells in the cluster are monitored, and the other wells in the cluster are controlled such as to cause their tubing head pressures or flow meter readings to be approximately constant for the duration of the test; b) deriving from step a a well injection estimation model for each tested well, which model provides a correlation between variations of the fluid flowrate attributable to the well under considerati

Abstract: A system for testing a wellbore fluid includes a test chamber having first and second platens therein. The chamber is in a thermally insulating enclosure. The enclosure includes a heating element. The platens simulate response of the wellbore fluid through an hydraulically induced fracture in subsurface rock formation. The system includes means to control a distance between the platens. A pump introduces the wellbore fluid into a space between the platens and another pump introduces a pressure test fluid into contact with the wellbore fluid. A respectve pressure sensor is in fluid communication with a discharge side of each pump, and a sensor is included to measure a parameter related to the position of the second platen or the space between the platens. A data acquisition and control device is configured to detect signals from the respective pressure transducers and the sensor.

Abstract: The invention relates to thermally stimulated oil recovery in horizontal wells, namely to the methods for estimation of Steam Assisted Gravity Drainage (SAGD) process characteristics. Method for estimation of SAGD process characteristics is characterized by the steps of measuring temperature along the injection well, measuring steam quality and injection rate at the inlet of the injection well, estimating the pressure distribution profile by using the data obtained, estimating steam injection profile by using the obtained pressure profile and injection rate combined with ID injection well model for pressure losses in the wellbore and heat exchange between injection well tubing and annulus. The obtained steam injection profile is used as an input parameter for a set of 2D cross-sectional analytical SAGD models taking into account reservoir and overburden formation properties impact on production parameters and SAGD characteristics.

Abstract: The critical desorption pressure is determined by pumping out an area within a well bore. As the pressure in that area is decreased, formation fluid from the surrounding rock matrix is drawn into the area. As the local pressure is decreased further, gaseous bubbles within the formation fluid will begin to form. The formation fluid is observed, and the formation of the gaseous bubbles is detected. The critical desorption pressure is determined based upon the presence of gas within the formation fluid. The concentration of gas within the formation fluid can then be determined based on the determination of the critical desorption pressure.

Abstract: Job monitoring methods and apparatus for logging-while-drilling equipment are disclosed. A disclosed example method includes obtaining a fluid associated with an underground geological formation, analyzing the fluid with one or more sensors to form respective ones of sensor outputs, identifying a downhole scenario associated with the fluid based on the sensor outputs, the identifying being performed while the sensors are within the underground geological formation, and selecting a telemetry frame type based on the identified downhole scenario.

Abstract: The invention is related to the development of gas condensate deposits and may be used to determine current condensate saturation in the near-wellbore zone in the formation. The method for the current condensate saturation determination in the near-wellbore zone requires the measurement of the formation rock parameters and formation fluid parameters before the start of gas-condensate production and creation of the numerical model of the neutron logging signal change during the production period for the measured formation rock parameters and formation fluid parameters and expected condensate saturation value. During the production period when the well productivity decreases, neutron logging is performed and then the measured signals are matched with the model calculations and based on the provision of the best match of the measured and simulated neutron logging signals condensate saturation is determined.

Abstract: The invention is related to the development of volatile oil deposits and may be used to determine current gas saturation in a near-wellbore zone in a volatile oil formation. The method for the current gas saturation determination in the near-wellbore zone requires the measurement of the formation rock parameters and formation fluid parameters before the gas accumulation start in the near-wellbore zone and creation of the numerical model of the neutron logging signal change during the production period for the measured formation and formation fluid parameters and expected gas saturation value. During the production period when the well productivity decreases, neutron logging is performed and then the measured signals are matched with the model calculations and based on the provision of the best match of the measured and simulated neutron logging signals gas saturation is determined.

Abstract: A flow rate measuring device has a flow rate measurement unit, an appliance registering unit, a calculating unit, a determining unit, a first appliance identifying unit, and a second appliance identifying unit. The appliance registering unit stores at least first gas flow rate variation profiles on activation of respective gas appliances coupled to a flow channel, and second gas flow rate variation profiles based on the control specific to the respective gas appliances. The first appliance identifying unit identifies which gas appliance is activated based on the first gas flow rate variation profiles on activation. When a determining unit detects a stop of any of gas appliances, the second appliance identifying unit identifies a gas appliance in continuous use by using the second gas flow rate variation profiles based on the control specific to the respective gas appliances.

Abstract: In some embodiments, apparatus and systems, as well as methods, may operate to acquire data representing a plurality of nuclear magnetic resonance (NMR) echo trains associated with a material, such as a geological formation. Additional operations may include inverting a model of at least one of the plurality of NMR echo trains to provide an estimated distribution of transverse relaxation time constants, inverting models of selected ones of the plurality of NMR echo trains using the estimated distribution of transverse relaxation time constants to provide an estimated diffusion distribution, and inverting a model of selected ones of the plurality of NMR echo trains, using the estimated distributions of transverse relaxation time constants and diffusion, to provide an apparent and an intrinsic probability density function to identify fluid types in the material.

Abstract: Monitoring of a wellbore which penetrates a reservoir is carried out by providing tracer material at one or more subterranean locations within or proximate the wellbore, so that tracer may enter the flow and be present in flow from the wellbore; repeatedly taking samples from the flow from the wellbore, and analyzing the samples for the presence of tracer, in the vicinity of the wellsite. Taking samples from the flow will generally be done at the surface and may be done by automatic equipment controlled by a programmed computer. The computer may be programmed to take action, such as operating a valve within the well, in response to detection of tracer. Sampling repeatedly and analyzing on site can provide information in something close to real time and thus integrates the use of tracers into an overall process of monitoring and control.

Abstract: A system and method monitor a hydrocarbon reservoir for drainage in volumetric three dimensions. Monitoring between wells is imperative for optimum reservoir management and is achieved by mapping the hydrocarbon fluid pathways in a producing reservoir. Unlike conventional 4D or time-lapse reflection seismic imaging systems that use a controlled active seismic source and records reflected seismic energy at receivers, the system and method exploit the minute vibrations, or micro-earthquakes generated in the reservoir layers that are induced by fluid movement. These microseisms are detected as the fluids move in the reservoir.

Abstract: A technique is disclosed for reducing an error in a controlled variable via model predictive control. A predicted error in the controlled variable is determined for a forward-looking control horizon based upon measured or computed variables. The integral of the predicted error is computed. If the error or the integral exceed a tolerance for a determined time period, the model predictive control algorithm is modified to drive the error or the integral to within a tolerance. The modifications to the control algorithm may include changes to coefficients for terms based upon the error and/or the integral of the error.

Abstract: A method for characterizing a desired property of a fluid downhole is described. In some non-limiting examples, the method comprises receiving an input signal representing sound speed of a fluid downhole, processing the input signal using a correlation equation expressing the desired property in terms of at least sound speed to produce an output signal representing the desired property, and outputting the output signal. In some examples, the correlation equation is derived through a chemometric analysis of a training data set, the training data set comprises a plurality of input values and a plurality of output values derived from said input values, between the desired fluid property and the first measured property, and the output values are calculated from the input values using a series of correlation equations. In at least one example, the desired property is gas oil ratio. In another example, the desired property is gas brine ratio.

Abstract: To develop a flow control system for use in a well, a multi-level approach is used, where the multi-level approach includes setting goals for the flow control system. According to the goals set, an overall design of the flow control system is specified, and based on the specified overall design for the flow control system, operation of the flow control system is simulated.

Abstract: A portable monitor used to measure landfill gas and landfill well parameters. The portable monitor includes a control unit and a measuring unit that can communicate wirelessly with one another. The control unit and/or measuring unit can include a heating arrangement to increase the temperature of one or more components in the control unit and/or measuring unit in cold environments.

Abstract: In some embodiments, an apparatus and a system, as well as a method and an article, may operate to obtain a formation fluid sample from a formation adjacent to a wellbore disposed in a reservoir, determine the sample saturation pressure of the formation fluid sample, repeat obtaining the formation fluid sample and determining the sample saturation pressure over a selected time period or number of samples, and determine a predicted ultimate formation fluid saturation pressure based on multiple determinations of the sample saturation pressure. The sample saturation pressures measured over selected time periods can be used to determine fluid sample contamination. Additional apparatus, systems, and methods are disclosed.

Abstract: A system and method for detecting abnormal operation of a hydrocracker includes a hydrocracker model. The model may be configurable to include one or more regression models corresponding to different operating regions of the portion of the hydrocracker. The system and method may also determine if a monitored temperature difference variable deviates significantly from the temperature difference variable predicted by the model. If there is a significant deviation, this may indicate an abnormal operation.

Abstract: A logging-while-drilling system for efficiently providing a reliable measurement of various petrophysical properties of subsurface earth formations.

Abstract: A method and apparatus for controlling oil well drilling equipment is disclosed. One or more sensors are distributed in the oil well drilling equipment. Each sensor produces a signal. A surface processor coupled to the one or more sensors via a high speed communications medium receives the signals from the one or more sensors via the high speed communications medium. The surface processor is situated on or near the earth's surface. The surface processor includes a program to process the received signals and to produce one or more control signals. The system includes one or more controllable elements distributed in the oil well drilling equipment. The one or more controllable elements respond to the one or more control signals.

Abstract: A method for determining permeability of a subsurface formation includes measuring a parameter related to fluid content of the formation at a first time from within a wellbore penetrating the formation. A rate of entry of fluid from the wellbore into the formation is determined from the measurement of the parameter made at the first time. The permeability is determined from the rate of entry.

Abstract: A device for detecting a flow of air from an exit end of a tube fed into an entrance end of the tube, including a bore having a first section with a first size bore size and a second section with a second bore size, an obstruction located within the bore between the first section and the second section, the obstruction configured to obstruct air flowing from the first section to the second section, and fixing means to fix the device to the tube so that the bore communicates with the exit end of the tube, wherein in use, an air pressure sensor is used to compare air pressure within the first bore section and air pressure within the second bore section, so that a pressure differential is indicative of an air flow within the bore.

Abstract: A method and system for determining formation properties based on a fracture treatment that may include collecting data from a fracture treatment for a well. A flow regime of the fracture treatment is determined based on the data. Formation properties may be determined based on the flow regime and the data.

Abstract: A low maintenance adjustable gas trap with a plurality of couplings, each coupling securing to a flow line of a drilling rig; a plurality of hammer unions each engaging a coupling; a plurality of base manifold pipes, each engaging a hammer union; a base manifold flow line engaging the base manifold pipes, a chimney pipe connected to the base manifold flow line with a controllable valve, a reducer connected to the chimney opposite the base manifold flow line; an expansion chamber component connected to the reducer; a restrictor mounted to the expansion chamber component opposite the reducer, wherein the restrictor has a diameter no more than ?rd a diameter of the expansion chamber component; and a conduit connection connected to the restrictor for engaging a conduit to flow a gas sample from the gas trap to a gas analyzer.

Abstract: The present document discloses techniques to perform an impulse well test for formation property estimation of subsurface reservoirs. It disclosures a method to obtain the optimum time range of a downhole isolation valve closure to achieve an acceptable depth of investigation for an impulse test and methodologies to optimize the execution of an impulse test using the simulated and measured real time bottomhole pressure data. It is emphasized that this abstract is provided to comply with the rules requiring an abstract which will allow a searcher or other reader to quickly ascertain the subject matter of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Abstract: A method that uses downhole fluid analysis in order to selectively collect and retain formation fluid samples in a drilling environment, as well as, control drilling using downhole fluid analysis.

Abstract: A system and method including a sensors deployed in a wellbore, the sensors measuring various downhole parameters. The system retrieves the relevant data from the sensors, validates the data, conditions the data, and analyzes the data to diagnose the wellbore and the reservoir to indicate trends therein. The system has the capability of enabling the characterization of the wellbore and reservoir by being linked to well test analysis tools. The system also has a screening analysis that is much less time consuming than well test analysis tools and that indicates to a user which wellbore and/or reservoirs should be subjected to the more robust and time consuming well test analysis tool.

Abstract: A method is disclosed, which is practiced by a reservoir simulator, for simulating a reservoir and generating a set of simulation results, the simulation results including a framework, the framework further including a plurality of grid cells, comprising: generating one or more static and dynamic regions within the grid cells of the framework of the simulation results, the static and dynamic regions each having region values, wherein the region values of the static regions cannot be allowed to change dynamically, and wherein the region values of the dynamic regions can be allowed to change dynamically.

Abstract: This invention relates to computing numerical solutions of linear systems of equations, specifically to implementing preconditioning of the coefficient matrix of such a system. The preconditioning applies to any coefficient matrix, dense or sparse, based on the solutions of a physical problem of unknown functions, commonly referred to as basis or interpolation functions, where the basis function spans more then one mesh element. Examples of such linear systems can result from, as examples, an electromagnetic analysis of printed circuit boards or field scattering in radar applications, fluid mechanics and acoustics. A method and system to compute a preconditioner for a coefficient matrix A that is compatible with the linear system of equations that provides basis function support over at least two mesh elements. Coupling of the preconditioner between partitions of a portioned mesh representation is only through basis functions at the partition boundaries.

Abstract: This invention relates to computing numerical solutions of linear systems of equations, specifically to implementing preconditioning of the coefficient matrix of such a system. The preconditioning applies to any coefficient matrix, dense or sparse, based on the solutions of a physical problem of unknown functions, commonly referred to as basis or interpolation functions, where the basis function spans more then one mesh element. Examples of such linear systems can result from, as examples, an electromagnetic analysis of printed circuit boards or field scattering in radar applications, fluid mechanics and acoustics. A method and system to compute a preconditioner for a coefficient matrix A that is compatible with the linear system of equations that provides basis function support over at least two mesh elements. Coupling of the preconditioner between partitions of a portioned mesh representation is only through basis functions at the partition boundaries.

Abstract: A method and system for characterizing formation fluids contaminated with drilling mud that compensates for the presence of such drilling mud. The operations that characterize formation fluids contaminated with drilling mud can be carried out in real-time. The operations also characterize a wide array of fluid properties of petroleum samples contaminated with drilling mud in a manner that compensates for the presence of drilling mud. The operations characterize the viscosity and density of petroleum samples contaminated with drilling mud at formation conditions in a manner that compensates for differences between formation conditions and flowline measurement conditions. The operations also derive live fluid density unaffected by contamination of mud filtrate based on a scaling coefficient dependent on measured gas-oil ratio of the formation fluid.

Abstract: Example methods and apparatus to determine phase-change pressures are disclosed. A disclosed example method includes capturing a fluid in a chamber, pressurizing the fluid at a plurality of pressures, measuring a plurality of transmittances of a signal through the fluid at respective ones of the plurality of pressures, computing a first magnitude of a first subset of the plurality of transmittances, computing a second magnitude of a second subset of the plurality of transmittances, comparing the first and second magnitudes to determine a phase-change pressure for the fluid.

Abstract: A simulation method for flow of fluid around a body, according to the present invention, comprising dividing a target domain of simulation into a plurality of computational unit domains named cubes, generating an uniform number of Cartesian mesh elements named cells, in each of the cubes, performing computation in the cubes in each computational step, and exchanging data between adjacent cubes after completion of each computational step. In dividing the target domain of simulation into cubes, division is repeated while a ratio between adjacent cube sizes is maintained in a certain range until cubes including a boundary between the body and the fluid, is small enough to obtain a desired resolution so that sizes of the cubes are appropriately determined according to a shape of the body.

Abstract: The present invention relates to a method for monitoring a fluid transfer process, including the steps: providing an allowable pressure profile; detecting a pressure occurring in the course of the fluid transfer process; comparing detected pressure with the allowable pressure profile and signaling an error, if the detected pressure is not within the allowable pressure profile. The allowable pressure profile is defined by interpolation points, the interpolation points being based on a probability function representing a family of pressure courses of a plurality of fluid transfer processes. The allowable pressure profile can be divided into at least two distinct process sections, each section corresponding to a distinct process phase of the fluid transfer process. The probability function is calculated from a family of test pressure curves and reflects the statistical behavior of the pipette system.

Abstract: A method for imaging a geologic deposit using data collected from a borehole includes: selecting an instrument for performing electromagnetic (EM) measurements, the instrument including at least one transmitter and at least one orthogonally oriented receiver; obtaining EM measurement data from the borehole with the instrument; transforming the EM measurement data to acoustic data; and estimating at least one of a direction and a distance from the instrument to the deposit from the data. A computer program product and a system are provided.

Abstract: A fingerprint processing system may include a fingerprint database for storing fingerprint data having at least one void therein. At least one processor may cooperate with the fingerprint database for inpainting data into the at least one void in the fingerprint data based upon propagating fingerprint contour data from outside the at least one void into the at least one void.

Abstract: A subsurface reservoir may be characterized and/or monitored based on fluid injection. For example, fluid may be injected into the reservoir, and data (e.g., seismic data, geodetic data, pressure data) relating to the injected fluid in the reservoir may be used to identify characteristics of the reservoir and/or to monitor the injected fluid in the reservoir. In some aspects, air or another type of surrogate fluid is injected into the reservoir, and the reservoir's viability as a carbon dioxide sequestration site can be analyzed based on response data collected from the reservoir. In some aspects, carbon dioxide is sequestered in the subsurface reservoir, and three-dimensional geodetic response data is collected and used to monitor and/or facilitate quality control.

Abstract: A method of hydrodynamics-based gridding (Hydro-Grids) for creating geologic models of subsurface volumes, such as reservoirs, is disclosed. Geologic data is obtained. Vertical grid surfaces are created. Lateral grid surfaces are created to correspond to surfaces of constant geologic time during the deposition of sediments in the subsurface volume. Geologic properties within each cell are represented as values within each cell created by the vertical and lateral surfaces. Reservoir performance is simulated using the represented geologic properties of the subsurface volume. A hydrocarbon reservoir is developed based on the simulated reservoir performance.

Abstract: A method and a tool that implements a method which includes measuring the viscosity and flow rates of formation fluids and obtaining the ratio of relative permeabilities of the formation fluids and wettability of the formation using the same.

Abstract: A method, system, and computer program product for performing oilfield surveillance operations. The oilfield has a subterranean formation with geological structures and reservoirs therein. The oilfield is divided into a plurality of patterns, with each pattern comprising a plurality of wells. Historical production/injection data is obtained for the plurality of wells. Two independent statistical treatments are performed to achieve a common objective of production optimization. In the first process, wells and/or patterns are characterized based on Heterogeneity Index results and personalities with the ultimate goal of field production optimization. In the second process, the history of the flood is divided into even time increments. At least two domains for each of the plurality of wells are determined. Each of the at least two domains are centered around each of the plurality wells. A first domain of the at least two domains has a first orientation.

Abstract: Multi-phase flow is estimated in a flow meter by measuring fluid pressure within the flow meter and using the measured pressure to calculate a density of the flow. A total flow rate through the flow meter is estimated based on the calculated density and a PVT analysis of the fluid. A corrected total mass flow rate is calculated using a liquid/gas slip correction technique. Fluid flow rates are further corrected with a discharge coefficient that varies with changes in the Reynolds number of the fluid. The gas and oil fractions can be determined from the corrected total mass flow rate and gas fraction.

Abstract: Methods and apparatus for improving the determination of at least one multiphase flow parameter of an earth formation comprising propagating within the formation a first salinity front, determining a first value of the at least one multiphase flow parameter, propagating in the formation a second salinity front and improving the determination of the at least one multiphase flow parameter from the first value for the at least one multiphase flow parameter and a saturation profile associated with the first and second salinity fronts within the formation.

Abstract: A method of analyzing a subterranean formation. The method includes specifying a volume of interest in the subterranean formation, specifying an injector wellsite that penetrates the volume of interest, specifying a first producer wellsite and a second producer wellsite, each of which penetrates the volume of interest, calculating a first Injectivity-Productivity Index (IPI) for a first injector-producer wellsite pair which includes the injector wellsite and the first producer wellsite, calculating a second IPI for a second injector-producer wellsite pair which includes the injector wellsite and the second producer wellsite, determining whether the first IPI is substantially equal to the second IPI to obtain an analysis result, and adjusting a wellsite operation based on the analysis result.

Abstract: A method and system operates a well having an outer casing, a tubing positioned inside the outer casing, and a plunger moveable within the tubing to periodically draw out a liquid slug. A chemical to slug size ratio is set by the operator. Thereafter, the gas flow rate is monitored and the well is shut-in when the gas flow rate drops below a predetermined threshold. After well shut-in, a calculated amount of chemical foaming agent is injected. The size of the liquid slug is calculated and then the well is opened, drawing the plunger and liquid slug up to the surface. The calculated amount of chemical foaming agent is calculated based on one or more previous liquid slug size determinations and the set chemical to slug size ratio.

Abstract: A method for predicting mechanical properties of a transverse isotropic region of a rock formation traversed by a well bore including running a logging tool in the well bore; the mass percentages of minerals present in the rock formation surrounding the well bore are measured with the logging tool. The density of the minerals present in the rock formation surrounding the well bore is determined. The porosity of the rock formation surrounding the well bore is measured. From the porosity and the measured mass percentages and density of the minerals, all the transverse isotropic elastic coefficients of the rock formation are determined in real time.

Abstract: A technique for estimating the permeability profile of a well includes generating a well and formation model. The technique includes producing the well so that hydrocarbons flow from the formation and through the well. The technique includes measuring pressure at a plurality of points along at least a portion of the well without an intervention in the well and estimating a permeability profile along the portion of the well by use of the plurality of pressure measurements.

Abstract: A method of predicting subsurface properties of a geologic formation includes acquiring seismic data for a subsurface region including the geologic formation of interest, computing seismic attributes of the measured seismic data over at least part of this geologic formation, determining internally consistent rock properties representative of the geologic formation, generating models of the same part of the geologic formation with these rock properties, computing synthetic seismic data from the models, computing the same attributes from these synthetic seismic data, and using Bayesian analysis to predict, from the probability of modeled attributes given the models, the probability of the actual subsurface properties given the measured attributes.

Abstract: An arrangement which utilizes an inexpensive flap valve/flow transducer combination and a simple local supervisory control system to monitor and/or control the operation of a positive displacement pump used to extract petroleum from geologic strata. The local supervisory control system controls the operation of an electric motor which drives a reciprocating positive displacement pump so as to maximize the volume of petroleum extracted from the well per pump stroke while minimizing electricity usage and pump-off situations. By reducing the electrical demand and pump-off (i.e., “pounding” or “fluid pound”) occurrences, operating and maintenance costs should be reduced sufficiently to allow petroleum recovery from marginally productive petroleum fields. The local supervisory control system includes one or more applications to at least collect flow signal data generated during operation of the positive displacement pump.

Abstract: A method for monitoring the movement of fluid through a subsurface formation of interest, comprising: a) providing a set of signals obtained by transmitting seismic waves through the formation of interest and receiving signals emanating from the multi-layered system in response to the seismic waves with one or more receivers located a distance from the seismic source(s), b) identifying one or more critically refracted waves among the signals so as to generate a first data set of refracted signals, c) repeating steps a) and b) after a period of time so as to generate a second data set of refracted signals, d) comparing the second data set to the first data set so as to generate a time-lapse data set, e) imaging the time-lapse data set using travel time tomography; and f) inferring information about the movement of fluid based on the image generated in step e).

Abstract: A low maintenance adjustable system for sampling gas from a well using a gas analyzer; a conditioning and filtering device; a gas trap having a plurality of couplings, a plurality of hammer unions, a plurality of base manifold pipes, a base manifold flow line, a chimney pipe connected to the base manifold flow line, a controllable valve, a reducer connected to the chimney, an expansion chamber component connected to the reducer, a restrictor mounted to the expansion chamber component, and a conduit connection connected to the restrictor for engaging a conduit to flow a gas sample from the gas trap to a gas analyzer.

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.