Abstract: A method for determining the complex response of a permeable stratum at the bottom of a producing well, the well comprising a well head fitted with an outlet valve and the bottom of the well comprising a height-adjustable pressure and flow rate sensor, comprising the following steps: periodically altering the degree to which the outlet valve is open, and, while the alteration is in progress:—measuring the pressure and flow rate in the well at the top/bottom of the stratum for a certain number of periods of alteration, after a certain delay; and—measuring the pressure and the flow rate in the well at the bottom/top of the stratum for a certain number of periods of alteration, immediately after the positioning of the sensor.

Abstract: The various embodiments herein provide a method for determining core wettability characteristics of reservoir rock samples based on modified form of Washburn equation. The method involves saturating a core sample with a first reservoir fluid such as water and imbibing with a second reservoir fluid such as oil. The change in square of the core mass with respect to time is monitored during an imbibition process to acquire a data to calculate a contact angle to determine the wettability of the sample. The contact angle is calculated by using the modified form of Washburn equation. A single or twin core sample is used to calculate the wettability characteristics. The method measures wettability characteristics in terms of contact angle and not in terms of wettability index.

Abstract: Various disclosed distributed acoustic sensing (DAS) based systems and methods include embodiments that process the DAS measurements to detect one or more contrasts in acoustic signatures associated with one or more fluids flowing along a tubing string, and determine positions of the one or more contrasts as a function of time. The detected contrasts may be changes in acoustic signatures arising from one or more of: turbulence, frictional noise, acoustic attenuation, acoustic coupling, resonance frequency, resonance damping, and active noise generation by entrained materials. At least some of the contrasts correspond to interfaces between different fluids such as those that might be pumped during a cementing operation.

Abstract: A processor accepts sensor data about a geological formation from a sensor. The sensor data is such that processing the sensor data using a processing technique to estimate a parameter of the geological formation without a constraint, whose value is not yet known, produces a plurality of non-unique estimates of the parameter. The processor accepts more than two time-displaced images of fluid sampled from the geological formation. The time displacements between the images are substantially defined by a mathematical series. The processor processes the images to determine the constraint. The processor processes the sensor data using the processing technique constrained by the constraint to estimate the parameter of the geological formation. The processor uses the estimated parameter to affect the drilling of a well through the geological formation.

Abstract: A system to monitor a status from a secondary location of a plurality of equipment on a drilling site, while simultaneously enabling preventive maintenance is described herein. A user can view at least one cycle, at least one control state, and at least one pressure. The user can also view equipment information, equipment repair history, and other information necessary to ensure that a piece of equipment has minimal down time.

Abstract: A system for monitoring the status of a plurality of tensioner assemblies and rig motion assemblies from a secondary location. The system not only monitors a status of a tensioner from a secondary location but simultaneously enables preventive maintenance to be ascertained remotely.

Abstract: A method to monitor a status from a secondary location of a plurality of equipment on a drilling site, while simultaneously enabling preventive maintenance is described herein. A user can view at least one cycle, at least one control state, and at least one pressure. The user can also view equipment information, equipment repair history, and other information necessary to ensure that a piece of equipment has minimal down time.

Abstract: Method comprises measuring temperature along an injection well, measuring a steam quality and an injection rate at an inlet of the injection well and estimating a pressure distribution profile. Then a steam injection profile is estimated using the obtained pressure distribution profile and the measured injection rate combined with a one-dimensional injection well model for pressure losses in the well and heat exchange between an injection well tubing and an annulus. The obtained steam injection profile is used as an input parameter for a set of two-dimensional cross-sectional analytical SAGD models. The models are based on energy conservation law and take into account reservoir and overburden formation properties, heat losses into the reservoir and overburden formation impact on production parameters and SAGD characteristics. SAGD process characteristics are estimated from the set of two-dimensional cross-sectional analytical SAGD models.

Abstract: A method for determining movement of a fluid contact in a subsurface reservoir includes measuring azimuthally sensitive resistivity at a first time from within a wellbore penetrating the subsurface reservoir. A first position of the fluid contact with respect to the wellbore is determined using the azimuthally sensitive resistivity measurements. After a selected time, the measuring azimuthally sensitive resistivity from within a wellbore penetrating the subsurface reservoir is repeated. Movement of the fluid contact from the first position is determined using the repeated azimuthally sensitive resistivity measurements.

Abstract: The invention relates to the use of distributed optical fibre sensors for distributed acoustic sensing, and in particular, modal analysis of distributed acoustic data obtained in-well to monitoring well integrity. By determining one or more acoustic modes corresponding to distributed speed of sound measurements within the wellbore, and analysing variations in the distributed speed of sound measurement it is possible to derive information relating to a formation and/or fluid in the wellbore.

Abstract: Cleanup monitoring and prediction in real time targeting estimation of pumpout volume versus final contamination, including detecting breakthrough of formation fluid to a sampling tool and detecting transition of cleanup regime from a predominantly circumferential cleanup regime to a predominantly vertical cleanup regime. Similar workflow can be employed for estimating contamination at the end of cleanup production for a given pumpout volume.

Abstract: A method having obtaining one or more porosity data of a subsurface of the Earth using a data acquisition tool; computing one or more permeability data from the porosity data using a transformation function; computing a first quantile regression function and a second quantile regression function of the one or more permeability data; producing a combined mean regression function of the one or more permeability data by summing the first quantile regression function and the second quantile regression function, wherein the first quantile regression function is multiplied by a first coefficient and the second quantile regression function is multiplied by a second coefficient; and using the combined mean regression function to predict a mean permeability of the subsurface.

Abstract: Various embodiments include apparatus and methods to monitor flow of single and multiple phase fluids. Sensors of a tool can be dispersed along the tool to collect measurements to be processed using an autocorrelation operation on the collected measurements to provide information relative to the phases of the fluid. Additional apparatus, systems, and methods are disclosed.

Abstract: A downhole tool for permeability calculation includes a body configured for insertion into and retraction from a horizontal well, and coupled with a computer system that includes an interface operable to receive (i) fluid properties associated with the horizontal well, under downhole production logging conditions; (ii) relative permeability to oil and relative permeability to water, for the horizontal well; and (iii) actual production logging data associated with the horizontal well. The computer system may also include one or more processors that are operable to (i) determine an approximate upper boundary and an approximate lower boundary of the horizontal well; (ii) divide the horizontal well into a plurality of well segments; and (iii) calculate, for each respective well segment, a horizontal permeability.

Abstract: A method for permeability calculation includes determining fluid properties associated with a horizontal well, relative permeability to oil and relative permeability to water, for the horizontal well, and an approximate upper boundary and an approximate lower boundary of the horizontal well. In accordance with a particular embodiment, the horizontal well may be divided into a plurality of well segments. Actual production logging data associated with the horizontal well may be received at an interface. For each respective well segment, a horizontal permeability is calculated using the fluid properties, relative permeability to oil, relative permeability to water and actual production logging data.

Abstract: A system and method for controlling an advancing water front in a reservoir toward a wellbore is provided. The system has a production control unit. The production control unit has a reservoir unit for producing a reservoir model and a production path unit for producing a production path model that determines at least one pressure parameter about the wellbore during a life of the wellbore. The production control unit has a production optimizer unit for producing a well plan that optimizes a function of the wellsite. The production control unit may be for controlling an advancing fluid front in the reservoir with at least one control device, and wherein a production path is constructed based on the well plan.

Abstract: A method of modeling a subsurface hydrogeologic system within a study area can include applying an electric current directly to the subsurface hydrogeologic system and monitoring a magnetic field generated by the electric current in the subsurface hydrogeologic system. An electric current distribution can be identified within the study area by an inversion process based on the magnetic field. A model of the electric current distribution can be created.

Abstract: A first analyzing step is a step that conducts numerical analysis of a flow field but does not conduct numerical analysis of a temperature field in a state in which a motor rotor is rotating. The second analyzing step is a step that conducts numerical analysis of both the flow field and the temperature field after the first analyzing step ends. Accordingly, before numerical analysis of the flow field and numerical analysis of the temperature field are conducted together, numerical analysis is conducted first on the flow field in first analyzing step before it is conducted on the temperature field. As a result, compared with when the second analyzing step is executed from the beginning without conducting the first analyzing step, the calculation load of the numerical analysis on an electronic calculator can be reduced, which enables the time that it takes to conduct the numerical analysis to be shortened.

Abstract: A method can include providing data for a field that includes fractures and a well; analyzing at least a portion of the data for times less than an interaction time; and outputting one or more values for a parameter that characterizes storage of a fluid in the field and one or more values for a parameter that characterizes transfer of the fluid in the field. Various other methods, devices, systems, etc., are also disclosed.

Abstract: A system and method for supplying an additive into a well is disclosed that includes estimating injection rates for the additives and setting of one or more fluid flow control devices in the well based on a computer model. 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 for predicting a pressure window for drilling a borehole in a formation includes: obtaining a pore pressure related data value of the formation using a data acquisition tool; predicting pore pressure uncertainty from the pore pressure related data value of the formation using a processor; estimating uncertainty of a pressure window for drilling fluid using the predicted pore pressure uncertainty using a processor; and applying the estimated uncertainty to the pressure window to provide a modified pressure window using a processor.

Abstract: Methods and systems for performing well network production optimizations are described. For example, in one embodiment, a method of allocating an applied resource throughout a well network includes receiving topological data into an analytical model of a well network having one or more wells. The topological data includes a plurality of performance curves that relate well performance to one or more levels of an applied resource. The method also includes determining an optimum allocation of the applied resource using the analytical model to maximize an operating parameter of the well network, including converting a portion the analytical model having one or more wells and a linear inequality relationship to a modified portion having a single variable and a linear equality constraint.

Abstract: Methods and systems are provided for allocating production among reservoir compartments by way of compositional and isotopic analysis. That is, where individual reservoir compartments contribute differing amounts of fluid to a commingled production stream, the methods herein determine the relative contribution of fluid volume from each reservoir compartment. Both a composition-based relative contribution and an isotope-based relative contribution of fluid from each reservoir compartment may be determined to allocate production to each reservoir compartment, the determinations respectively being based on composition mass balances and stable carbon isotope mass balances of components. The combination of both allocation analysis provides quality checks on the results that identify improper allocations that may arise. In addition to production allocation, other applications include, among others, determining the effectiveness of intervention operations and providing feedback for adjusting operations.

Abstract: A method and a system is disclosed for determining RON and/or MON values from constant volume combustion chamber apparatuses capable of producing pressure versus time combustion profiles having a fast combustion region and a slow combustion region, where data from the two regions is used to compute RON and/or MON values for light distillate fluid samples using a series expansion equation.

Abstract: A system and method for determining fluid distribution in subterranean reservoirs including determining a water saturation in macroporosity from the capillary pressure data representative of the macroporosity using a saturation height function, correcting capillary pressure data representative of microporosity to have an entry pore value equivalent to a pore size defining the microporosity, determining a water saturation in the microporosity from the corrected capillary pressure data representative of the microporosity, and using the macroporosity water saturation and the microporosity water saturation to estimate fluid distribution within the subterranean reservoir. The system and method may also include the estimation of hydrocarbon reserves.

Abstract: A simple, applicable in the field, and extra-equipment free method is provided for determining steam dryness directly in a thermal recovery of high-viscosity oil. A non-condensable gas is added into a saturated steam being injected into a well. The presence of non-condensable gas changes partial steam pressure. Correspondingly the steam condensation temperature also changes. The borehole temperature or pressure measurements can be used to evaluate the steam dryness.

Abstract: A method for computing or estimating relative permeability for fractional multi-phase, multi-component fluid flow through a porous medium, which employs a 3D digital representation of a porous medium and a computational fluid dynamics method to calculate flow rates, pressures, saturations, velocities and other flow parameters, is described. The method employs a unique method which integrates a precursor simulation used to generate a set of variables like pressure, saturation and velocity distribution associated with a selected storage plane in the 3D digital representation of a porous medium, which variables are used as inlet condition in the workflow of a second simulation that can generate values of fractional flow rates, pressures, saturations, velocities, or other parameters of wetting and non-wetting phases, which can be used to compute or estimate relative permeability values or other fluid transport properties of the porous medium.

Abstract: The pore structure of rocks and other materials can be determined through microscopy and subjected to digital simulation to determine the properties of multiphase fluid flows through the material. To ensure reliable results, the digital rock model is first analyzed via a series of operations that, in some embodiments, include: obtaining a three-dimensional pore/matrix model of a sample; determining a flow axis; verifying that the dimension of the model along the flow axis exceeds that of a representative elementary volume (REV); selecting a flow direction; extending model by mirroring if pore statistics at a given saturation are mismatched for different percolating phases; and increasing resolution if the smallest nonpercolating sphere dimension is below a predetermined threshold. This sequence of operations increases reliability of results when measuring relative permeability using the model and displaying relative permeability measurements to user.

Abstract: Methods and apparatus for measuring individual phase fractions and phase flow rates in a multiphase flow based on velocity of the flow, speed of sound through the fluid mixture, and the density of the fluid mixture. Techniques presented herein are based on measuring frictional pressure drop across a flowmeter conduit, determining a surface roughness term for the conduit during initial flow tests or through other mechanical means, implementing a correction method to balance the momentum equation, and calculating the fluid mixture density using the measured pressure drop. The techniques may be applicable to measuring flow parameters in horizontally oriented conduits and, more generally, conduits of any orientation.

Abstract: A method of completing a hydrocarbon lateral well in a target shale formation. The method uses a data log generated from an optical flow cell assembly to identify areas in the lateral well of high free gas porosity. By evaluating such data, an operator can group “like” rock, determine stage length and variation in stage length, and determine perforation cluster spacing and location. The flow cell assembly can also be used in a completion program to assist in the steering of a lateral well being drilled below the target formation.

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: A method for exploiting underground porous media via injection or production of a fluid is disclosed, wherein repetitive seismic records are interpreted taking into consideration the seismic frequency band in the evaluation of pore pressures. After inversion of 4D seismic data, at least two sets of seismic speeds are available which correspond to different moments in time. A Hertz-type power-law is then used to evaluate pore pressures, wherein the Hertz coefficient is determined using laboratory ultrasound or sonic measures. Then the coefficients are adjusted using a measurement of the attenuation of the ultrasound or sonic waves. Fluid flow is then monitored within the porous media by determining whether variation in seismic speed is due to the variation of pore pressure or to fluid substitution, using the adjusted Hertz equation.

Abstract: A wellbore fluid pressure measurement system includes a densometer adapted to measure a fluid density of a fluid flowing in a tubing system; and a monitoring unit communicably coupled to the densometer. The monitoring unit is adapted to receive a plurality of values representative of the fluid density from the densometer and includes a memory adapted to store the plurality of values representative of the fluid density; and one or more processors operable to execute a fluid pressure measurement module. The module is operable when executed to determine a fluid pressure of the fluid based on at least a portion of the values representative of the fluid density.

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 method, apparatus and computer-readable medium for determining an influx at a wellbore is provided. A flowback parameter is obtained for a plurality of flowback events at the wellbore prior to a current flowback event. An average of the flowback parameter (?) and a standard deviation (?) of the flowback parameter is determined from the plurality of prior flowback parameters. An alarm threshold is set based on the determined average and the standard deviation. A current flowback parameter is measured and the influx is determined when the current flowback parameter meets the alarm threshold.

Abstract: A method for updating an earth model with fractures or faults using a microseismic data using mechanical attributes of an identified faults or fracture by matching a failure criterion to observed microseismic events for an identified fault or fracture.

Abstract: Systems, methods, and media for processing formation pressure test data are provided. The method includes determining using a processor, a plurality of regressions for measurements of the formation pressure test data, and determining that two or more of the plurality of regressions represent a fluid code. The method also includes combining the two or more of the plurality of regressions representing the fluid code to generate a first fluid-type regression, and combining two or more other ones of the plurality of regressions representing a second fluid code to generate a second fluid-type regression. The method further includes determining that the first fluid-type regression and the second fluid-type regression are in a first hydraulic zone, and calculating a location of a boundary between the first fluid-type regression and the second fluid-type regression by extrapolating the first and second fluid-type regressions to a point of intersection therebetween.

Abstract: Methods and related systems are described for estimating fluid or rock properties from NMR measurements. A modified pulse sequence is provided that can directly provide moments of relaxation-time or diffusion distributions. This pulse sequence can be adapted to the desired moment of relaxation-time or diffusion coefficient. The data from this pulse sequence provides direct estimates of fluid properties such as average chain length and viscosity of a hydrocarbon. In comparison to the uniformly-spaced pulse sequence, these pulse sequences are faster and have a lower error bar in computing the fluid properties.

Abstract: A well passing through a geological formation is fitted with a tube, open at its bottom end, that is filled with a fluid. Another fluid is in the annular space between the tube and the wall of the well, the two fluids exhibiting an interface situated in the annular space. A hydraulic balance of the fluids of the well is disturbed and the trend of certain quantities is measured. These measurements are moreover simulated by computer by using different sets of values for the physical parameters, and efforts are made to estimate the geological formation. A comparison of the measurements with the simulation results makes it possible to identify an optimum set of values for the parameters.

Abstract: A method of constructing a well log of a quantitative property representative of a porous formation, from sample measurements and log data, is disclosed. A quantitative property (mineralogical proportions) of samples selected from among a set of samples is measured and each sample is grouped into homogeneous classes regarding the log data. The average value of the quantitative property is then determined in each class. A well log representing the probability of assigning a sample to each class as a function of depth is constructed. Finally, the well log representing the quantitative property as a function of depth is constructed from the log representing the assignment probability and from the average values.

Abstract: A system for monitoring a condition of a downhole electrical submersible pump (ESP) assembly is disclosed. The system includes: a downhole assembly configured to be disposed in a wellbore in an earth formation; the ESP assembly connected to the downhole assembly and including a motor and a pump, the ESP assembly in electrical communication with a surface electrical source via a conductor; a power gauge unit configured to measure the electrical power supplied to the ESP assembly; and a processor configured to receive data from the power gauge unit and calculate a flowrate of the ESP assembly based on at least the electrical power supplied to the ESP assembly. Also disclosed is a method of monitoring a condition of a downhole ESP assembly.

Abstract: A method to determine one or more borehole corrected formation properties using measurements made using a logging tool disposed in a borehole penetrating an earth formation is disclosed. The measurements are used to determine an apparent conductivity tensor for the formation and, for a set of parameters, a parameter value for each parameter in a subset of the set of parameters. A parameter value for each parameter in the set of parameters not in the subset is provided and a borehole-inclusive modeled conductivity tensor is computed. The apparent conductivity tensor and the borehole-inclusive modeled conductivity tensor are iteratively used to optimize the parameter values, and the optimized parameter values are used to compute an optimized conductivity tensor. A borehole corrected conductivity tensor is computed using the optimized conductivity tensor, and the borehole corrected formation properties are determined using the borehole corrected conductivity tensor and/or the optimized parameter values.

Abstract: A methodology improves sampling and characterization of heterogeneous, unconventional hydrocarbon-bearing regions. The methodology is designed to integrate consistently across measurements and scales. Additionally, the methodology involves characterizing various scales, such as regional-scale heterogeneity, wellbore-scale heterogeneity, core-scale heterogeneity, sample-scale, and pore-scale heterogeneity. The results are integrated across the multiple scales based on results obtained from the characterization of the scales. The methodology further comprises determining data propagation across the multiple scales in a hydrocarbon-bearing region.

Abstract: A method includes controlling a lift-gas compression process, controlling a lift-gas extraction process, and controlling a production separation process. The method also includes receiving asset data and optimizing the lift-gas compression process, the lift-gas injection process, and the production separation process according to the asset data.

Abstract: A method to monitor a status from a secondary location of a plurality of equipment on a drilling site, while simultaneously enabling preventive maintenance for the plurality of equipment is described herein. A user can view at least one cycle, at least one control state, and at least one pressure. The user can also view equipment information, equipment repair history, and other information necessary to ensure that a piece of equipment has minimal down time.

Abstract: A system to monitor a status from a secondary location of a plurality of equipment on a drilling site, while simultaneously enabling preventive maintenance is described herein. A user can view at least one cycle, at least one control state, and at least one pressure. The user can also view equipment information, equipment repair history, and other information necessary to ensure that a piece of equipment has minimal down time.

Abstract: Systems and methods for imaging operations data as a three-dimensional image, which include rendering a three-dimensional image of an object having at least one attribute, a marker in the object, and one or more operations values relative to one or more respective positions on the marker in the object. A data structure comprising a data field, the data field comprising a three-dimensional image of an object having at least attribute, a marker and one or more operations values relative to one or more respective positions on the marker in the object at a selected time.

Abstract: A computer assisted method to monitor a status from a secondary location of a plurality of equipment on a drilling site, while simultaneously enabling preventive maintenance is described herein. A user can view at least one cycle, at least one control state, and at least one pressure. The user can also view equipment information, equipment repair history, and other information necessary to ensure that a piece of equipment has minimal down time.

Abstract: Electrical property contrast difference maps of the subsurface formations may be produced using surface and/or near surface array of transmitters and receivers tuned to emit and receive electromagnetic (EM) signals. The electrical property may be resistivity or conductivity. The maps may be time based. A time based trend change may be used to predict the location and movement of fluids within the hydrocarbon bearing or any other subsurface zones where resistivity and/or conductivity values of the fluids within these zones change over time.

Abstract: A method for determining mobile water saturation in a reservoir having a borehole extending through the reservoir is disclosed. The method involves obtaining a first borehole data log while the reservoir is subjected to first fluid conditions, and causing a mobile water displacement in the reservoir by changing the fluid conditions in the borehole to cause the reservoir to be subjected to second fluid conditions, the second fluid conditions differing from the first fluid conditions. The method further involves obtaining a second borehole data log under the second fluid conditions, and estimating the mobile water displacement using the first and second data logs, the estimated mobile water displacement providing an estimate of the mobile water saturation in the reservoir.