Abstract: A method and a system for predicting a molecular weight of a hydrocarbon fluid are provided. An exemplary method includes measuring a density of the hydrocarbon fluid, obtaining an alternative measurement of a physical property of the hydrocarbon fluid, calculating an index value for the hydrocarbon fluid from the alternative measurement, and calculating a predicted molecular weight using an equation that combines the density with the index value. The predicted molecular weight is provided as an output.

Abstract: A system for analysis of isolated and connected porosities of a porous formation using permittivity is disclosed. An electrical subsystem can provide electrical signals for one or more of the porous formation or a representation of the porous formation; and the system can determine one or more of a rate of permittivity change (RPC) or permittivity ratio (PR) from a first estimation model that relates permittivity measurements and frequencies that are associated with the electrical signals, so that the system can generate a second estimation model using one or more of the RPC or the PR, associated with the isolated and connected porosities, where the second estimation model can be used with a total porosity of the porous formation to estimate or predict an isolated porosity and a connected porosity of a production porous formation.

Abstract: The present disclosure provides a processing device including: a coarse-grained pruning unit configured to perform coarse-grained pruning on a weight of a neural network to obtain a pruned weight, an operation unit configured to train the neural network according to the pruned weight. The coarse-grained pruning unit is specifically configured to select M weights from the weights of the neural network through a sliding window, and when the M weights meet a preset condition, all or part of the M weights may be set to 0. The processing device can reduce the memory access while reducing the amount of computation, thereby obtaining an acceleration ratio and reducing energy consumption.

Abstract: Distributed artificial intelligence (AI) can be used to monitor a wellbore operation in some examples described herein. In one such example, physical equipment can be positioned at a surface of a wellsite to support a drilling operation at the wellsite. Each piece of physical equipment may include a sensor module, a processor communicatively coupled to the sensor module, and a memory. The memory can include an AI module configured to determine a condition associated with the equipment by analyzing sensor data from the sensor module using one or more machine-learning models. The memory additionally can include a warning module for causing the processor to output a warning notification based on the condition. The memory further can include a communications module for causing the processor to transmit a communication indicating the condition to a destination via a network. The communication may be different from the warning notification.

Abstract: A chemical injection system for a resource extraction system includes a controller having a memory and a processor. The memory stores instructions that cause the processor to receive a first pressure from a first pressure sensor of the resource extraction system, receive a second pressure from a second pressure sensor of the resource extraction system, determine a flowrate of a produced fluid of the resource extraction system based on the first pressure and the second pressure, determine an ion concentration of the produced fluid, and adjust an injection rate of a chemical into the resource extraction system based on the flowrate of the produced fluid, the ion concentration of the produced fluid, or both.

Abstract: A method to estimate the likely downhole conditions in the wellbore and reservoir by Inverse modeling well flow simulation history matched with field sensor data. The invention presents a method for automating sensor data processing through cleaning, transformation, and identification of stable states. This process is crucial for the selection of data to be simulated and matched without human review. The matched simulations are subjected to a state-space model in order to assign a probability to a given unknown state. This probability is updated at each time step. As the well undergoes transition over time including decline, the drift of the likely state of operation is orchestrated to allow physically constrained movement to a proximate space.

Abstract: A method for managing oilfield water. Oilfield water data is grouped into discrete and non-overlapping groups. Outliers are removed from the data. Features of the remaining data are analyzed to identify most discriminative feature. The data is separated into training data and testing data, and the training data is fit into a model that shows the best precision, accuracy and recall. The model is confirmed using the testing data. Upon confirmation of the accuracy of the model, the model is applied to data for a new proposed oilfield well, and a new proposed project is implemented or disapproved based on a result of the identified model that predicts water production of the new proposed oilfield well.

Abstract: The present invention is related to computer implemented method for characterizing a target fluid of a hydrocarbon reservoir under uncertainty providing a set of fluid properties from a limited amount of information.

Abstract: A method of integrated modeling using multiple subsurface models includes receiving multiple sets of input values associated with a hydrocarbon formation of the Earth. The method also includes receiving a network model that includes one or more assets configured to distribute a flow of hydrocarbons from the hydrocarbon formation to a processing facility. The method further includes generating the multiple subsurface models based on the multiple sets of input values, wherein each subsurface model comprises a set of input values of the multiple sets of input values, and wherein each subsurface model represents a production of the flow of hydrocarbons from the hydrocarbon formation. The method also includes applying the multiple subsurface models to the network model to generate an integrated model comprising multiple production rates of hydrocarbons via the one or more assets over time. The method further includes identifying at least one asset to adjust based on the integrated model.

Abstract: Downhole fluid volumes of a geological formation may be estimated using nuclear magnetic resonance (NMR) measurements, even in organic shale reservoirs. Multi-dimensional NMR measurements, such as two-dimensional NMR measurements and/or, in some cases, one or more well-logging measurements relating to total organic carbon may be used to estimate downhole fluid volumes of hydrocarbons such as bitumen, light hydrocarbon, kerogen, and/or water. Having identified the fluid volumes in this manner or any other suitable manner from the NMR measurements, a reservoir producibility index (RPI) may be generated. The downhole fluid volumes and/or the RPI may be output on a well log to enable an operator to make operational and strategic decisions for well production.

Abstract: The present disclosure relates to a method of processing seismic signals comprising: receiving a set of seismic signals, applying a wavelet transformation to the set of signals and generating transformed signals across a plurality of scales. Then for each scale determining coherence information indicative of the transformed signals and generating a comparison matrix comparing the transformed signals, then outputting seismic attribute information based on combined coherence information.

Abstract: A system, method and program product for evaluating a prospect. The method includes: receiving prospect information regarding a prospect for natural resource exploration; extracting a set of characteristics based on the prospect information; identifying a set of similar prospects and a set of prospect exploration results, based on the set of characteristics; receiving a success estimate for the prospect; validating the success estimate based on the set of characteristics, the set of similar prospects, and the set of prospect exploration results to determine inconsistencies in the success estimate; and approving the success estimate or receiving an updated success estimate, based on the inconsistencies in the success estimate.

Abstract: A method of integrated modeling using multiple subsurface models includes receiving multiple sets of input values associated with a hydrocarbon formation of the Earth. The method also includes receiving a network model that includes one or more assets configured to distribute a flow of hydrocarbons from the hydrocarbon formation to a processing facility. The method further includes generating the multiple subsurface models based on the multiple sets of input values, wherein each subsurface model comprises a set of input values of the multiple sets of input values, and wherein each subsurface model represents a production of the flow of hydrocarbons from the hydrocarbon formation. The method also includes applying the multiple subsurface models to the network model to generate an integrated model comprising multiple production rates of hydrocarbons via the one or more assets over time. The method further includes identifying at least one asset to adjust based on the integrated model.

Abstract: Some aspects of what is described here relate to seismic profiling techniques. A seismic excitation is generated in a first directional section of a first wellbore in a subterranean region. Seismic responses associated with the seismic excitation are detected in directional sections of a plurality of other wellbores in the subterranean region. A fracture treatment of the subterranean region is analyzed based on the seismic responses. In some instances, a multi-dimensional seismic velocity model of the subterranean region is generated based on the seismic responses.

Abstract: A well exploration, services and production architecture for access to one or more well exploration, services or production (ESP) applications may be configured such that standardization of the one or more components provides for operability across multiple platforms. A deployment blueprint may specify parameters that must be met by a well ESP appliance deployed to provide access to one or more well ESP applications. Deployment rules may be based on the deployment blueprint that provides for order of deployment of components and constraints associated with packaging the components, including one or more well ESP applications, in a container. A user interface accesses the well ESP applications of the well ESP appliance based on an authorization or verification of the user. To maintain access to all data by all users, data storage for all processes of any components, including the well ESP applications, is hosted at a remote file storage system.

Abstract: A method for monitoring movement of a fluid interface in a composite reservoir includes receiving data related to a composite reservoir. The composite reservoir includes an uninvaded oil zone, a water-invaded transition zone, and an aquifer. A model is generated using the data. The model is updated in response to movement of a fluid interface between the water-invaded transition zone and the uninvaded oil zone in the composite reservoir is identified. The model is also updated in response to movement of water from the aquifer toward the wellbore is also identified, before the fluid interface reaches a wellbore formed in the composite reservoir. A remedial action is determined to take in the wellbore in response to the movement of the fluid interface, the movement of the water, or both.

Abstract: Based on demand signals from multiple sources, the timing and amount of well tasks, such as material delivery, drilling, and/or waste removal, may be predicted. The well tasks may be organized as card elements on a graphical user interface, with the card elements being arranged based on the sequence in which the well tasks are scheduled. The sequence of the well tasks and the arrangement of the card elements on the graphical user interface may be updated automatically based on real-time data.

Abstract: A shale brittleness sweet spot evaluation method is provided, comprising: determining a brittleness evaluation formula of shale brittleness indexes, shale mineral volume percent content and shale total organic matter mass percent content according to a shale volume-mass conversion formula and a brittleness calculation formula containing shale total organic matter volume percent content and the shale mineral volume percent content; drawing a shale brittleness grading chart of a research area target interval according to the brittleness evaluation formula and measured shale mineral volume percent content values and shale total organic matter mass percent content values of multiple shale samples of the research area target interval; and evaluating shale brittleness sweet spots of the research area target interval.

Abstract: A portion of an anisotropy formation through which a wellbore is formed can be identified. An estimate of an elastic anisotropy parameter for the portion can be adjusted based on a first quality control analysis using the elastic anisotropy parameter for the portion. The first signal representing the elastic anisotropy parameter for the portion. The estimate of the elastic anisotropy parameter for the portion can be adjusted based on a second quality control analysis using estimates for the elastic anisotropy parameters for two or more portions of the anisotropy formation.

Abstract: Provided herein are systems and methods for hydraulic fracturing in earth. Systems may comprise a first well comprising sensors configured to collect sensor data at the first well. The calibration data may comprise sensor data, hydraulic fracture treatment conditions of the first well, geological data from an area containing the first well, or production date of oil or gas from the first well. The calibration data may be analyzed with the aid of one or more processors to generate an integrated 3-D model of hydraulic fracturing and fluid flow in the wellbore and reservoir of the first well. The system may further comprise a second well configured to operate according to simulation data generated from the integrated 3-D model of the first well and hydraulic fracture treatment conditions received from a user device. The user device may be configured to communicate with a server comprising the one or more processors.

Abstract: Systems, devices, and techniques for determining downhole fluid contamination are disclosed. In one or more embodiments, phase-related properties are measured for a reservoir fluid having a determined composition. An equation-of-state (EOS) isselected and/or tuned based, at least in part, on the measured phase-related properties and the tuned EOS is applied to estimate fluid property values for a reference fluid over specified ranges of at least two thermodynamic properties. Contaminant reference data are generated that correlate the estimated fluid property values for the reference fluid with respective contaminant levels. Within a wellbore, a fluid sample is analyzed to determining a fluid property values. A contaminant level is identified that corresponds within the contaminant reference data to the determined fluid property value of the fluid sample.

Abstract: There is an oil and gas zone effectiveness evaluation method. The oil and gas zone effectiveness evaluation method has the steps of: obtaining a controlling factor parameter distribution of a target interval; obtaining an evaluation parameter lower limit value of an industrial oil and gas reservoir; obtaining an accumulation parameter value of each grid coordinate point according to the controlling factor parameter distribution; obtaining an evaluation parameter processing value of each grid coordinate point according to the evaluation parameter, the evaluation parameter lower limit value and the accumulation parameter value of the grid coordinate point; and obtaining a zone evaluation value of the target interval according to the evaluation parameter processing value of the grid coordinate point. There also is an apparatus that is capable of improving the evaluation coincidence rate.

Abstract: Disclosed herein is a formation evaluation method including estimating a total porosity of an earth formation as a function of bulk density and total nuclear magnetic resonance (NMR) porosity of the earth formation. The total porosity of the earth formation as estimated underrepresents bitumen content. A gas filled porosity of the earth formation is estimated as a function of the bulk density and the total NMR porosity. A kerogen volume of the earth formation is estimated as a function of the gas filled porosity and a total organic carbon content of the earth formation. A bitumen filled total porosity is determined as a function of the estimated kerogen volume and the estimated total porosity of the earth formation. A corrected kerogen volume of the earth formation is determined as a function of the estimated kerogen volume and the estimated total porosity of the earth formation.

Abstract: A method is described for subsurface hydrocarbon reservoir characterization including receiving a time-lapse electromagnetic (EM) dataset and a flow dataset; inverting the time-lapse EM dataset using a parametric inversion that models steel well casings to determine a volume of fluid-changed reservoir; inverting the time-lapse EM dataset and the flow dataset using a joint inversion that honors the volume of the fluid-changed reservoir to determine relative permeability and capillary pressure; and characterizing flow characteristics in the volume of the fluid-changed reservoir. The method may be executed by a computer system.

Abstract: A method including: obtaining geophysical data for a subsurface region; generating, with a computer, at least two subsurface property models of the subsurface region for at least two subsurface properties by performing an inversion that minimizes a misfit between the geophysical data and forward simulated data subject to one or more constraints, the inversion including generating updates to the at least two subsurface property models for at least two different scenarios that both fit the geophysical data with a same likelihood but have different values for model materiality, with the model materiality being posed as an equality constraint in the inversion, wherein the model materiality is a functional of model parameters that characterize hydrocarbon potential of the subsurface region; analyzing a geophysical data misfit curve or geophysical data misfit likelihood curve, over a predetermined range of values of the model materiality to identify the at least two subsurface property models that correspond to a h

Abstract: A computerized method and system for of operating an oil/gas facility for processing oil and gas from a reservoir. The method includes steps of receiving input data concerning condensate phase and gas phase components in the reservoir, the input data characterizing both phase components, determining a pore capillary pressure of the reservoir based on the received input data which characterizes the phase components, determining PVT parameters of the reservoir phase components based on the determined pore capillary pressure, and controlling a setting of the oil/gas facility based on the determined PVT parameters of the reservoir phase components.

Abstract: A method for determining a favorable time window of an infill well of an unconventional oil and gas reservoir, which comprises the following steps: S1, establishing a three-dimensional geological model with physical properties and geomechanical parameters; S2, establishing a natural fracture network model in combination with indoor core-logging-seismic monitoring; S3, calculating complex fractures in hydraulic fracturing of parent wells; S4, establishing an unconventional oil and gas reservoir model and calculating a current pore pressure field; S5, establishing a dynamic geomechanical model and calculating a dynamic geostress field; S6, calculating complex fractures in horizontal fractures of the infill well in different production times of the parent wells based on pre-stage complex fractures and the current geostress field; S7, analyzing a microseismic event barrier region and its dynamic changes in infill well fracturing; and S8, analyzing the productivity in different infill times, and determining an inf

Abstract: Disclosed are methods, systems, and computer-readable medium to perform operations including: generating a grid representation of a reservoir model comprising a simulation well, the grid comprising a plurality of grid-blocks, wherein the simulation well is centered in grid-block (i) of the plurality of grid-blocks; simulating, using the grid representation, grid-block pressures for the plurality of grid-blocks over a plurality of time steps; calculating an equivalent radius (ro*) for a grid-block (i+1), wherein the grid-block (i+1) is adjacent to the grid-block (i); and calculating, based on the equivalent radius and a grid-block (i+1) pressure, a shut-in bottom-hole pressure (SBHP) for the simulation well.

Abstract: The systems and methods described herein include training a well performance predictor based on field data corresponding to a hydrocarbon field in which a well is to be drilled; generating a number of candidate well parameter combinations for the well and predicting a performance of the well for each candidate well parameter combination using the trained well performance predictor; and determining an optimized well parameter combination for the well such that the predicted performance of the well is maximized.

Abstract: A method and system are described for hydrocarbon exploration, development and production. The method relates to performing regression and/or classification in subsurface models to support decision making for hydrocarbon operations. The evaluation may then be used in performing hydrocarbon operations, such as hydrocarbon exploration, hydrocarbon development and/or hydrocarbon production.

Abstract: A method of identifying hydrocarbon seeps that are connected to hydrocarbon reservoirs and for identifying in situ conditions of hydrocarbon reservoirs is disclosed. The method comprises, obtaining a sample from an area of interest, such as a sediment sample or water column sample near a hydrocarbon seep; analyzing the sample to detect microbial signatures that are specific to families associated with hydrocarbon reservoirs; and using the signature to determine whether the hydrocarbon seep is connected to a hydrocarbon reservoir and to identify properties of the hydrocarbon reservoir.

Abstract: A method, apparatus, and program product model an oilfield asset by selecting, for each of multiple sectors of the oilfield asset, a sector model from among a collection of sector models, building a multi-resolution integrated asset model of the oilfield asset using the selected sector model for each of the sectors, and performing a computer simulation using the multi-resolution integrated asset model. The collection of sector models for each sector includes multiple sector models modeled at varying resolutions. In addition, the multi-resolution integrated asset model includes a surface network model that couples the selected sector models to one another. As such, different sectors of an oilfield asset may be modeled at varying resolutions to balance accuracy and turnaround time when performing integrated oilfield asset modeling.

Abstract: A method of drilling a well includes receiving depth specific drill parameters associated with drilling wells within a field; receiving drilling report entries associated with drilling the wells within the field; applying a report analysis engine to the drilling report entries to determine a drilling event; determining a field-specific drilling model utilizing the depth specific drill parameters and drilling event; prescribing a drilling recipe using a drilling analysis engine applied to the field-specific drilling model; and drilling the well in accordance with the drilling recipe.

Abstract: A method may include generating, for a first time period having a first length, an instance of a collector object. The collector object may be configured to collect values over time periods having the first length. The instance of the collector object may be updated based on one or more values from a first record. The first record may store values collected over a second time period having a second length. A valuation operation may be performed based at least on the first instance of the collector object. The performance of the valuation operation may require values spanning at least one time period having the first length. Related systems and articles of manufacture, including computer program products, are also provided.

Abstract: A system for automated model-based drilling includes a plurality of surface-based sensors configured to sense one or more rig parameters in real-time, a hydraulic modeler unit configured to generate a real-time model of an equivalent circulating density based on one or more rig parameters, a control module configured to continually determine whether the equivalent circulating density is within pre-determined safety margins of a safe pressure window, and a forward parameters simulator configured to, while the equivalent circulating density is within the pre-determined safety margins of the safe pressure window, determine an optimal drilling parameter to change and an optimal drilling parameter amount of change. The control module changes a rig setting corresponding to the optimal drilling parameter to change to the optimal drilling parameter value automatically or outputs the optimal drilling parameter to change and the optimal drilling parameter value to a display for manual adjustment by a driller.

Abstract: In some aspects, the present disclosure includes systems and methods for optimizing one or more of a number of sensors on a drillstring or the locations of the sensors on the drillstring, or the types of the sensors. The method includes determining a number of sensors to place on a drillstring, a location for each of the sensors based, and types of sensors based, at least in part, on one or more of a state reduction technique and an optimization framework. The method includes disposing the selected number of sensors along the drilling and performing a drilling operation.

Abstract: An underwater camera and water quality monitoring system provides the capability of shooting video or time lapse photography together with recording water condition or quality measurements in an integrated device for stationary, submerged deployment in a body of water under study. The underwater camera and water quality monitoring system has a configurable delay from submerged deployment in the waterway until image/video recording and water quality measurement sampling begins, allowing aquatic life activity to resume in the vicinity after disruption of the system deployment. The monitoring device may be used in combination with recognition software utilizing artificial intelligence techniques to identify species or individuals observed during monitoring.

Abstract: Described herein are various embodiments of computer-implemented methods, computing systems, and program products for analyzing a flood operation on a hydrocarbon reservoir. For example, an embodiment of a computer implemented method of using producer centered polygons to identify at least one infill drilling location in a hydrocarbon reservoir having a plurality of producers and at least one injector is provided.

Abstract: Apparatus and associated methods relate to computerized system for predicting the quantity of oil and/or gas production at an oil site, where a prediction curve for oil and/or gas data transitions from a first fitted curve (e.g., a hyperbolic decline curve) to a second fitted curve (e.g., an exponential decline curve) at a transition point, the transition point being determined by progressively/iteratively identifying curvature changes in the first fitted curve over an initial time period by comparing a running list of terminal decline rates (Dmin) with a predetermined curvature threshold, and setting the occurrence of the transition point at the point where the rate of change of the terminal decline rate is less than the predetermined curvature threshold. In an illustrative example, the second fitted curve may use the value of Dmin that minimizes the deviation between successive forecasts.

Abstract: A system includes a database server and a plurality of processing nodes. The plurality of processing nodes are configured to receive mass spectrometry data from a plurality of samples; align the mass spectrometry data to correct for changes in retention time to generate a reference alignment; cluster compounds across the plurality of samples; store the reference alignment and clustered compound data to the database server; receive additional mass spectrometry data from additional samples; align the additional mass spectrometry data to a reference alignment within the database; correlate the compounds from the additional samples with the clustered compound data; classify the compounds; perform statistical analysis on the classified compounds to identify compounds meeting threshold criteria; and provide an indication of compounds meeting the threshold criteria.

Abstract: The disclosed embodiments include a method, apparatus, and computer program product for determining optimal flow control device (FCD) properties that would yield to a prescribed shape of the injection flow rate profile. For example, in one embodiment, a computer implemented method is configured to perform the steps of: determining a reference location along a production length of the injection well; determining a reference value equal to the injection flow rate profile at the reference location along the production length of the injection well; defining a target injection profile using the reference value; determining a pressure distribution along the production length of the injection well based on the target injection profile; determining a FCD distribution profile using the target injection profile and the pressure distribution; and determining FCD properties that yields the target injection profile based on the FCD distribution profile.

Abstract: Systems and methods for generating and storing completion design models in a central data repository of models for completion design, well bore (such as fracturing or drilling) or other operations is shown.

Abstract: A processor-based system utilizes analytical techniques that organize large volumes of hydrocarbon well data around spatial patterns, well characteristics, and/or calculated performance measurements in order to analyze the large volumes of well data faster and more efficiently. For example, one embodiment uses a custom-created library of metadata and rules that enables the underlying processor-based system to transform large volumes of oil and gas well data into a more organized and efficient database, saving many hours of labor. In particular, some of the organizational techniques include combinations of over 100 descriptors for each well, a variety of well-ranking regimes (such as Tiers, Quintiles, and Deciles), production profiles, and other groupings (such as Play Type, Operator Class, and the like).

Abstract: Provided are systems and methods of hydrocarbon well monitoring, assessment and development including: obtaining wellhead production data for a well; determining, based on the wellhead production data for the well, observed constant wellhead production rates for the well; for each of the observed constant wellhead production rates, determining a corresponding wellhead pressure and a cumulative production volume for each occurrence of the observed wellhead production rate, and a depletion rate for the observed constant wellhead production rate; determining, based on the depletion rates for the observed constant wellhead production rates, a depletion rate for the well that is indicative of a change in a flowing wellhead pressure of the well as a function of production volume of the well. Embodiments include undertaking well and reservoir development operations based on the depletion rate determined for the well.

Abstract: In some embodiments, an apparatus and a system, as well as a method and article of manufacture, may operate to parameterize a geological formation in terms of initial earth model parameters, and generate predicted data by simulating a tool response using earth model parameters. Further activity may include determining a difference between calibrated data and the predicted data; and simultaneously adjusting calibration parameters and the earth model parameters such that the difference between them satisfies selected convergence criteria, so that a controlled device can be operated according to at least one of updated calibration parameters, updated calibrated data, or updated earth model parameters. Additional apparatus, systems, and methods are disclosed.

Abstract: The present disclosure describes methods and systems, including computer-implemented methods, computer program products, and computer systems, for determining a mudweight of drilling fluids in a hydrocarbon reservoir. One computer-implemented method includes: receiving pore pressure data of a rock formation in the hydrocarbon reservoir; determining permeability data of fractures of the hydrocarbon reservoir; determining Hoek-Brown failure criterion data; and determining a safe mudweight window based on the pore pressure data of the rock formation, the permeability data of the fractures, and the Hoek-Brown failure criterion data.

Abstract: A method determines the performance index of subterranean rock. In one embodiment, a performance index method determines a performance index for subterranean rock of an area. The area includes a well. The method includes determining a time period during producing the well. The method also includes determining the performance index from data of the time period from the equation PI=(q/dd)*(cum./GPI). The term PI is the performance index, and the term q is the average daily rate of the well for the time period. The term dd is the average drawdown per day of the well for the time period, and the term cum. is the cumulative production of the well for the time period. The term GPI is the gross perforated interval of the well for the time period.

Abstract: Provided are embodiments that include determining cellular volumes having a saturation value for a given time that is above a threshold saturation value and having a location within a threshold distance of a perforation location of a production well, determining a nearest cell distance defined by a minimum distance between the perforation location and locations of the determined cellular volumes, determining an operating bottom-hole pressure (BHP) and a surface well pressure (SWP) for the well for the given time, determining a minimum operating BHP for the well for the given time according to a specified relationship of the operating BHP, the SWP, the threshold saturation value, the threshold distance, and the nearest cell distance, and operating the well at a production rate to maintain a BHP of the well at or above the minimum operating BHP for a time period associated with the given time.

Abstract: Systems and methods for calculating reservoir characteristics, including well pressure and flow rates are disclosed. Plotting and monitoring a plot of pressure (p) and flow rate (q) as p/q on a y-axis and 1/q on an x-axis can provide insight into well characteristics with zero RMS error.

Abstract: Methods for computer modelling of a pressure transient behavior after shut-in and during fall-off of an injection event are provided to provide estimates of stimulated reservoir volume, formation permeability, stress contrast across the target and adjacent zones, fracture dimensions, fracture beyond the target zone, and pump pressure limits for maintaining fractures within the target zone, especially in fractured tight reservoirs.