Abstract: A numerical procedure is disclosed to improve the prediction of heat fronts when simulating hot fluid injection in viscous hydrocarbon reservoirs. The mathematical model is composed of the conventional governing equations that describe multiphase fluid flow and energy balance. The reservoir geometry can be partitioned into a regular Cartesian grid or an irregular corner-point geometry grid. The numerical procedure uses the finite different (FD) method to solve the flow equations and the discontinuous Galerkin (DG) method to solve the energy balance equation. The proposed FD-DG method is an alternative to the traditional solution procedure that uses the FD method to solve both the flow and the energy equations. The traditional method has the deficiency that it may require excessive number of grid cells to achieve acceptable resolution of the heat fronts.

Abstract: A computer-implemented reservoir prediction system, method, and software are provided for modeling the behavior of non-Newtonian fluids in subterranean reservoirs while accounting for shear-rate dependent viscosity and permeability reduction with a skin zone characterized by a traditional skin factor and an apparent skin factor. A non-Newtonian fluid injection pressure or a non-Newtonian fluid injection rate is computed at steady-state responsive to reservoir data associated with a subterranean reservoir, injection data for a non-Newtonian fluid, and fluid data for the non-Newtonian fluid. The shear-rate dependent viscosity can further be applied to a well model in numerical reservoir simulation to improve the well model.

Abstract: Systems and methods for basin to reservoir modeling to identify any hi-grade drilling targets based on the linking of static and dynamic reservoir rock and fluid properties. Static, present-day, reservoir and field scale description grids or unstructured meshes are transformed into dynamic (through time) simulation grids or unstructured meshes that can subsequently be used for input to dynamic calculators. Basin modeling may be performed at the reservoir scale, providing a link between present-day and the historical process that acted on the rocks and fluids.

Abstract: A surface seismic survey is generated or obtained from Earth's surface and is based on time in which acoustic waves are reflected to Earth's surface. One or more tools measure density and sonic velocity of a subsurface formation. An estimate of acoustic impedance is obtained from the density and the sonic velocity to generate a synthetic seismic survey. The synthetic seismic survey and the surface seismic survey are compared and/or correlated. The acoustic impedance can be iteratively estimated until the synthetic seismic survey matches the surface seismic survey. Matching the surface seismic survey with the synthetic seismic survey may ensure that the surface seismic survey may be calibrated in actual depth.

Abstract: A new approach is disclosed for measuring the pressure of tight gas reservoirs, using information obtain from continuous injection prior to hydraulic fracture stimulation. The technique can be obtained utilizing either bottom-hole or surface pressure gauges and properly instrumented surface injection pumps. The analysis is completed by plotting injection and rate data in a specialized form from terms arranged in Darcy's radial flow equation to obtain a curve or trend. The key component to proper application of this technique is to obtain both baseline and one or more calibration data sets. These calibration data sets are obtained by either increasing or decreasing the injection pressure and/or rate from the baseline data. Initial reservoir pressure is assumed, but the calibration data indicates if the guess was too high or low. Accurate estimates of reservoir pressure may be obtained in a few iterations.

Abstract: A system and method for determining an orientation of a reservoir feature from an unoriented core. The method includes selecting an arbitrary inclined plane in a longitudinal or transverse cross sectional CT scan image of the unoriented core; flattening the inclined plane by realigning all voxels within a volume of the unoriented core so as to obtain a horizontal plane in a realigned core; selecting a transverse cross sectional CT scan image of the realigned core where a desired feature is present; determining a correcting angle to be added to an angle of a flat-bed contact plane of the realigned core relative to a reference mark in the realigned core to obtain a correct inclination angle relative to compass map coordinates; determining a first angle between a direction perpendicular to the feature relative to the reference mark; and determining a second angle by adding the correcting angle to the first angle.

Abstract: An approach is provided for shared mobile web services. A community including multiple mobile web servers providing a shared web service is designated. In the event one mobile web server is unavailable to service a request directed to the shared web service, another mobile web server is selected to provide the shared web service.

Abstract: A method for simulating downhole conditions is described. The method includes receiving configuration information about a well system in a production configuration, the well system including annular fluids disposed therein and receiving heat source information associated with a heat source disposed within the well system. The method also includes simulating temperature transfer in the well system during a production scenario based at least on the configuration information and the heat source information and predicting pressure buildup in the annular fluids based on the simulated temperature transfer in the well system.

Abstract: A method to detect flow rate from a displacement unit entailing locating the displacement unit in a fluid path, monitoring a piston position in the displacement unit for a stroke direction change, starting a timer upon a stroke direction change, monitoring at least one check valve position for an alteration of position, stopping the timer upon the alteration of position, calculating a time between the stroke direction change and the alternation of position, calculating a volume of the displacement unit and calculating the flow rate from the displacement unit by dividing the volume of the displacement unit by the calculated time.

Abstract: A method for determining wettability of a solid, such as a reservoir rock material includes disaggregating the material, for example by grinding and placing the disaggregated material on the surface of the fluid. The wettability is analyzed based on whether a portion of the material floats on or sinks into the fluid. The method is well suited for heterogeneous solid materials that have mixed wetting characteristics and/or have varying surface types. The fluid can be evaluated as a potential treatment fluid or a component thereof that can be used for treating the rock formation. For example, the potential treatment fluid can include a surfactant or an oxidizing agent. A simple observation can be made whether substantially all of the material placed on the surface of the fluid sinks into the fluid, or the portions of floating and sinking material can be weighed.

Abstract: A drilling control system monitors and compares drilling and completion operation sensor values and autonomously acts in response to conditions such as a kick or surge. Sensors in various combinations may monitor return fluid flow rate, fluid inflow rate, wellhead bore pressure, temperature of returning fluid, torque, rate of penetration and string weight change. The control system has corresponding control logic to monitor, warn and act based on the sensor inputs. The actions may include the warning of support personnel, closing an annular blowout preventer, shearing drill pipe using a ram shear, pumping heavier fluid down choke and kill lines, disconnecting the riser or various other actions.

Abstract: Methods for determining the quality of data gathered in a wellbore in a subterranean formation including (a) collecting a formation fluid sample in the wellbore in the subterranean formation using a formation tester for receiving the formation fluid, wherein the formation tester is lowered to at least one depth in the wellbore in the subterranean formation by a conveyor; (b) acquiring a wellbore measurement (“WM”) from the least one depth with the formation tester; (c) determining from the WM a measured quality value (“MQV”); (d) assigning a threshold value (“TV”) to the MQV; (e) assigning a range value (“RV”) to the MQV, based on geometric scaling of the TV, the RV defining the limits of the MQV above and below the TV; and (f) calculating a score value (“SV”) based on the MQV, the TV, and the RV, wherein the SV is a number between 0 and 2*TV, and wherein the quality of the WM increases as the SV increases.

Abstract: An apparatus and method for well control and monitoring including an independent web server computer integrated with a pump controller located at each well in an oil field. The well controller locally controls the well pump, processes well and pump data, generates surface and downhole cards, and communicates production reports, recommendations for production improvements, and production statistics to remote sites via the internet. The controller can be queried remotely to provide production reports, etc. Furthermore, the controller can initiate alerts via email, text messaging, or internet messaging, for example, during fault conditions.

Abstract: A multi-phase process fluid is passed through a vibratable flowtube. Motion is induced in the vibratable flowtube. A first apparent property of the multi-phase process fluid based on the motion of the vibratable flowtube is determined, and an apparent intermediate value associated with the multi-phase process fluid based on the first apparent property is determined. A corrected intermediate value is determined based on a mapping between the intermediate value and the corrected intermediate value. A phase-specific property of a phase of the multi-phase process fluid is determined based on the corrected intermediate value.

Abstract: Methods and apparatus for determining phase fractions (relative concentrations) within a multiphase fluid mixture, in the presence of an injected hydrate inhibitor. Combining this phase fraction information with a hydrate inhibitor injection rate (HIIR) enables resolving oil and water flow rates for the phase fractions. The liquid flow rates and a total combined flow rate of the fluid mixture—determined based on a differential pressure of the fluid mixture through a given area—enable resolving a gas flow rate.

Abstract: A system and method for use in a downhole tool having a fluid density measurement device positioned therein are provided. In one example, the method includes deploying the downhole tool at a first station in a borehole. The downhole tool is moved from the first station to a second station in the borehole. A plurality of fluid density values of fluid within the borehole between the first and second stations are measured using the fluid density measurement device in the downhole tool. The plurality of fluid density values may represent a continuous log of fluid densities between the first and second stations.

Abstract: Methods and systems analyze continued flow data in well testing data.

Abstract: Methods, systems, devices, and products for estimating a parameter of interest of an earth formation. The method may include using a correction factor to conduct a flow rate analysis on fluid sampled from the formation via a probe contacting a wall of the borehole, wherein the correction factor compensates for total compressibility; determining at least one of: i) the product of formation porosity and total compressibility; ii) system compressibility; and iii) initial formation pressure; or determining a mobility of the formation using a slope of a linear relationship of a time-dependent pressure of the fluid with respect to a formation flow rate. The parameter of interest may be i) formation mobility or ii) formation permeability. The correction factor may be determined using formation compressibility. The correction factor may be determined using at least one of: i) gas saturation; ii) oil saturation; and iii) water saturation.

Abstract: Downhole drilling fluid measurements are made as a function of time or as a function of depth. A change in the downhole drilling fluid measurements is correlated to a feature of a formation penetrated by a drill bit or to a feature of fluids in the formation. The downhole drilling fluid measurements may include density, photoelectric factor, hydrogen index, salinity, thermal neutron capture cross section (Sigma), resistivity, slowness, slowing down time, sound velocity, and elemental composition. The feature may include fluid balance, hole-cleaning, a kick, a shallow water flow, a formation fluid property, formation fluid typing, geosteering, geostopping, or an environmental correction. A downhole system has a measurement-while-drilling tool or a logging-while-drilling tool and a processor capable of obtaining the downhole drilling fluid measurements and correlating the change in the downhole drilling fluid measurements.

Abstract: Disclosed dielectric logging tools and methods employ three or more receive horn antennas positioned between at least two transmit antennas, which can also be horn antennas. The logging tools can operate in the range between 100 MHz and 10 GHz to provide logs of formation permittivity, formation conductivity, standoff distance, and electrical properties of material in the standoff gap. Logs of water-saturated porosity and/or oil movability can be readily derived. The presence of additional receive antennas offers a significantly extended operating range, additional depths of investigation, increased measurement accuracy, and further offers compensation for tool standoff and mudcake effects. In both wireline and logging while drilling embodiments, at least some disclosed dielectric logging tools employ a set of three axially-spaced receive antennas positioned between pairs of axially-spaced transmit antennas.

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 respective 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: An automatic method for providing geological trends and real time mapping of a geological basin using a mass spectrometer. The method provides information from a mass spectrometer on fluid samples from a wellbore into a geochemical surface well log with graphical tracks in real time. The dataset includes geochemical, engineering, and geological. The viewable geochemical well log provides information on well fluids and rock, and displays data in graphical tracks on client devices. The mass spectrometer receives samples from a gas trap connected to the wellbore, performs analysis on the samples, and communicates in real time to a geochemical surface well log with a plurality of graphical tracks which is then further communicated to a client device via a network.

Abstract: Permeability prediction systems and methods using quadratic discriminant analysis are presented. At least one disclosed method embodiment includes: acquiring formation property measurements at a plurality of positions along at least one borehole in a study area; identifying clusters in a plurality of points representing the formation property measurements at the plurality of postions; and determining a system permeability value for each cluster. Quadratic Discriminant Analysis (“QDA”) is used to associate one the clusters with each position along the one or more boreholes, thereby determining a system permeability prediction for each position. The total system permeability can then be predicted by aggregating the system permeability predictions.

Abstract: Clustering analysis is used to partition data into similarity groups based on mathematical relationships between the measured variables. These relationships (or prototypes) are derived from the specific correlation required between the measured variables (data) and an environmental property of interest. The data points are partitioned into the prototype-driven groups (i.e., clusters) based on error minimization. Once the data is grouped, quantitative predictions and sensitivity analysis of the property of interest can be derived based on the computed prototypes. Additionally, the process inherently minimizes prediction errors due to the rigorous error minimization during data clustering while avoiding overfitting via algorithm parameterization. The application used to demonstrate the power of the method is pressure gradient analysis.

Abstract: The invention is a method for optimizing working (EXP) of a deposit of fluid traversed by a network of fractures that involves determining the transitory exchange terms between matrix blocks and fractures (FFA, FFN), for any type of available information (INFO) concerning the network of fractures, regardless of the level of knowledge of the fractured environment.

Abstract: A system includes a downhole formation fluid sampling tool and a processor. An optical spectrometer of the downhole formation fluid sampling tool is able to measure an optical characteristic of a formation fluid flowing through the downhole formation fluid sampling tool over a plurality of wavelengths. The optical spectrometer generates optical spectra data indicative of this optical characteristic. The processor is designed to receive the optical spectra data generated by the optical spectrometer and to estimate a formation volume factor of the formation fluid based on the optical spectra data.

Abstract: There is provided a computer-implemented method for estimating flow of fluid into a production well extending into a reservoir comprising fluid, the well comprising a central tubing and an annulus surrounding the central tubing. The annulus is connected to the reservoir so as to receive fluid at one or more inflow locations. The central tubing has at least one inlet, arranged to allow fluid to flow from the annulus into the central tubing, and is located downstream of the one or more inflow locations. The production well further comprises one or more devices arranged to measure a temperature of fluid within the annulus at a plurality of points along the length of the annulus.

Abstract: The present invention is directed toward a method and an apparatus to investigate and quantify a leakage rate for a fluid between a first pipe and a second pipe, the first pipe being surrounded by at least a portion of the second pipe, where the pipes are arranged in a well in a ground and where a measuring arrangement including a flow meter and a pressure meter is put into fluid communication with an annulus defined by the first pipe and the second pipe, where fluid in the gaseous phase is conveyed through the measuring arrangement, as the annulus is used as a separation chamber for gas and liquid.

Abstract: A method for water monitoring about a deviated well is disclosed. The method includes positioning a series of electromagnetic (EM) receivers in a completed deviated wellbore, said receivers being spaced along substantially the length of the well located in a region of a reservoir to be monitored. The method also includes positioning an electromagnetic (EM) source at a first Earth surface location. Then the EM source is activated for a first survey measurement of the reservoir, and an EM field detected at each EM receiver is recorded. The EM source is moved to a second Earth surface location, and activated for a second survey measurement of the reservoir, and an EM field detected at each EM receiver is recorded. From the first and second survey measurements at each of the receivers, an inversion is performed to determine position of water about (and specifically below) the horizontal well.

Abstract: Provided are methods, systems, and computer-readable media for determining capillary pressure in a basin/reservoir. Well log data is obtained that includes permeability log data, porosity log data, water saturation log data, and oil saturation log data. Thomeer parameters for a multi-pore system of a Thomeer model are determined by evaluating an objective function that measures the mismatch between the well log data and modeled data having the Thomeer parameters as input. The objective function is iteratively evaluated using linear equality constraints, linear inequality constraints, and nonlinear equality constraints until convergence criteria are met.

Abstract: Interaction of adsorbing chemicals with a downhole tool presents inaccuracies in the adsorbing chemical measurement and analysis. The principles of the present disclosure provide a method and system of sampling fluids including an adsorbing chemical in a subterranean reservoir. One method may include modeling an interaction between the adsorbing chemical and a downhole tool, applying the model to a measurement of the adsorbing chemical, and adjusting the measurement in response to applying the model.

Abstract: A non-transitory computer-readable medium includes computer-executable instructions for presenting dumpflood data to a user by implementing steps on a computer. The steps include: receiving first data describing a first subsurface volume; receiving second data describing a second subsurface volume that is deeper than the first subsurface volume; calculating pressures required for a fluid to flow in a borehole from the first volume to the second volume as a function of vertical height of the first volume (h1), permeability of the first volume (k1), vertical height of the second volume (h2), permeability of the second volume (k2), a first damage factor (S1) representing damage to the first volume, and a second damage factor (S2) representing damage to the second volume; and displaying on a computer display a graphical representation of the calculated pressures and inputs used to calculate the pressures.

Abstract: Pressure of a fluid in a geological formation is predicted using measured temperature and pressure changes following the creation of a pressure reduction in a flowline in fluid communication with the fluid in the geological formation.

Abstract: Systems and methods for metric learning include iteratively determining feature groups of images based on its derivative norm. Corresponding metrics of the feature groups are learned by gradient descent based on an expected loss. The corresponding metrics are combined to provide an intermediate metric matrix as a sparse representation of the images. A loss function of all metric parameters corresponding to features of the intermediate metric matrix are optimized, using a processor, to learn a final metric matrix. Eigenvalues of the final metric matrix are projected onto a simplex.

Abstract: A method for surveying, may include receiving, by a processor, first survey data from a first source, the first source comprising a first signal generated by a subsurface earth formation in response to a passive-source electromagnetic signal, wherein the electromagnetic signal is generated by an electroseismic or seismoelectric conversion of the passive-source electromagnetic signal. The method may also include receiving, by the processor, second survey data from a second source and processing the first survey data and the second survey data to determine one or more properties of a subsurface earth formation.

Abstract: A method and computer-readable medium for determining a scattered wave particle velocity for a formation is disclosed. In aspects, the method may include: defining an embedded grid of the formation, and defining a contrast grid of the formation that includes a contrast feature of the formation; calculating a Green's function over the embedded grid; calculating a first scattering vector of the contrast feature for a first offset between the embedded grid and the contrast grid; determining the scattered wave particle velocity for the contrast feature at the first offset using the calculated Green's function and the first scattering vector; calculating a second scattering vector of the contrast feature for a second offset between the embedded grid and the contrast grid; and determining the scattered wave particle velocity for the contrast feature at the second offset is determined using the calculated Green's function and the second scattering vector.

Abstract: A multi-phase process fluid is passed through a vibratable flowtube. Motion is induced in the vibratable flowtube. A first apparent property of the multi-phase process fluid based on the motion of the vibratable flowtube is determined, and an apparent intermediate value associated with the multi-phase process fluid based on the first apparent property is determined. A corrected intermediate value is determined based on a mapping between the intermediate value and the corrected intermediate value. A phase-specific property of a phase of the multi-phase process fluid is determined based on the corrected intermediate value.

Abstract: An apparatus for determining the concentration of a conductive fluid present in a fluid filled bore hole is described. Such apparatus are known as water hold-up meters and are frequently used in oil, gas and water filled bore holes. In bore hole applications, data bandwidth between a down hole device and the surface can be limited, while determining water hold-up based on down hole measurements can be data intensive. A technique is proposed for calculating the water hold up that requires less data to be transmitted between the down hole device and the surface.

Abstract: A method for determining the profile of fluids inflowing into multi-zone reservoirs provides for a temperature measurement in a wellbore during the return of the wellbore to thermal equilibrium after drilling and determining a temperature of the fluids inflowing into the wellbore from each pay zone after perforation at an initial stage of production. Specific flow rate for each pay zone is determined by a rate of change of the measured temperatures.

Abstract: Testing water contamination around oil or gas wells. To determine a testing zone around an oil or gas well, multiple variables are received by data processing apparatus. The variables include variables associated with an oil or gas well, variables associated with an entity performing hydraulic fracturing in the oil or gas well, and variables associated with inhabitable regions surrounding the oil or gas well, to name a few. The multiple variables are processed by the data processing apparatus. In response to the processing, a zone around the oil or gas well within which to test for contamination due to the hydraulic fracturing in the oil or gas well is determined.

Abstract: Analysis evaluates formation fluid with a downhole tool disposed in a borehole. A plurality of possible constituents is defined for the formation fluid, and constraints are defined for the possible constituents. The constraints can include boundary constraints and constraints on the system's dynamics. The formation fluid is obtained from the borehole with the downhole tool over a plurality of time intervals, and density of the obtained formation fluid is obtained at the time intervals. To evaluate the fluid composition, a state probability distribution of the possible constituents of the obtained formation fluid at the current time interval is computed recursively from that at the previous time interval and by assimilating the current measured density of the obtained formation fluid in addition to the defined boundary/dynamic constraints.

Abstract: A method is disclosed for operating an oil pool based on a reservoir model gradually deformed by means of cosimulations. A map of a property of the pool is obtained by a stochastic simulation of a first random function. A correlation coefficient is chosen between the first random function and a second random function with an identical mean and covariance. The map is modified by a cosimulation of the two random functions by using the correlation coefficient. The correlation coefficient is modified and the cosimulation step is reiterated to deform the map and minimize a matching objective function. Finally, the pool is operated by implementing an operating scheme accounting for the deformed map.

Abstract: A sensor assembly includes an optical computing device having an integrated computational element (ICE) configured to optically interact with a fluid stream and detect a first characteristic of a substance within the fluid stream. The optical computing device is configured to generate a first signal corresponding to the first characteristic. The sensor assembly also includes a parameter sensor configured to measure a second characteristic of the fluid stream and generate a second signal corresponding to the second characteristic and a processor communicatively coupled to the optical computing device and the parameter sensor. The processor is configured to receive the first and second signals and determine a mass flow rate of the substance.

Abstract: A method for determining a characteristic of an underground formation with a fluid is described. The method includes providing a sample material of the underground formation; measuring the permeability and the porosity of the sample material; performing a drainage test on the sample material using the fluid; estimating the threshold pressure of the sample material from the drainage test, the permeability and the porosity measurements; and determining the receding contact angle of the fluid on the sample material from the threshold pressure. The sample material can be disaggregated material.

Abstract: Computer-implemented systems and methods are provided for generating corrected performance data of water flooding of an oil reservoir system based on application of a statistical correction factor methodology (SCF). For example, data related to properties of the oil reservoir system and data related to a water flooding scenario are received. Water flooding performance data is generated based on application of an analytical water flooding performance computation methodology. Based on application of the SCF methodology to the generated water flooding performance data, corrected water flooding performance data is determined, representative of oil recovery by the water flooding of the oil reservoir system. The SCF methodology can also be used to evaluate water production based on parameters such as water-oil ratio and water cut, identify possible analog reservoirs that have similar water production performance, and calculate a Gross Injection Factor to account for water loss in the reservoir.

Abstract: A multicomponent induction logging tool uses a nonconducting mandrel. A central conducting member including wires that electrically connect at least one of the antennas to another of the antennas. Electrodes disposed about the transmitter antenna form a conductive path through a borehole fluid to the central conducting member.

Abstract: Job monitoring methods and apparatus for logging-while-drilling equipment are disclosed. A disclosed example method includes identifying a downhole scenario based on a property of an underground geological formation, selecting a first telemetry frame type based on the identified downhole scenario, conveying an identifier representative of the selected first telemetry frame type to a downhole fluid sampling tool, and receiving a first telemetry data frame from the downhole fluid sampling tool, the telemetry data frame containing fluid analysis parameters for a fluid, and being constructed in accordance with the selected first telemetry frame type.

Abstract: A method of determining rate and phase of fluid produced from or injected into a hydrocarbon well includes obtaining first temperature and pressure measurements from sensors at the well. The first temperature and pressure measurements are applied to a plurality of predictive well models to calculate an estimated value of fluid rate and phase composition from each of the predictive well models responsive to the temperature and pressure measurements. A first fluid rate and phase composition result is derived from the estimate value of fluid rate and phase composition from each of the predictive well models.

Abstract: A computerized monitoring system and corresponding method of monitoring the status and health of a blowout preventer. The system includes a graphics display at which a graphical user interface (GUI) displays the health of various sealing elements and control systems by way of “traffic light” indicators. The health indicators are evaluated, by the monitoring system, based on a risk profile for each of the indicated elements and control systems. The risk profiles are evaluated based on inputs such as measurement inputs, feedback signals, mechanical positions, diagnostic results, drilling conditions, and other status information of the blowout preventer at a given time and based on levels of redundancy and levels of deviation from normal conditions. The GUI includes recent history of changes in operating condition, and alarm indications such as poor health, along with the times of those events.

Abstract: A method of determining parameters relating to the flow performance of subterranean sources is described using the steps of measuring a total flow rate and pressure at a reference datum for at least two different flow rates, allocating the flow from each of the sources using identified concentrations of characteristic components, and using the total flow rate, pressure and the allocation to determine selective inflow performance relationships for each source.