Abstract: Systems and methods for controlling an ESP installed in a well. The ESP is operated at a first voltage, and the current actually drawn by the ESP motor is monitored and compared to an expected current. If the actual current differs from the expected current, the actual horsepower load on the ESP motor is determined by multiplying an expected horsepower load by the ratio of the actual current to the expected current. A load saturation curve for the actual horsepower load is determined, and a voltage is identified on this curve at which the corresponding current is minimized. The ESP motor is then operated at this new voltage to optimize the efficiency of the motor.

Abstract: A subject information acquisition device includes a first holding member that holds a subject of a patient, a first probe that detects an acoustic wave having propagated through the first holding member and that performs a scanning operation, a first holding-member support located on a patient side from a scanning range of the first probe and that reduces bending of the first holding member, and a second probe located on the patient side from the scanning range of the first probe.

Abstract: A computer-readable medium including program instructions for drilling a borehole. When the program instructions are executed by one or more processors of a computer system operatively associated with a drill rig, the program instructions cause the processor to carry out the steps of initiating a drilling phase and monitoring a drill parameter during the drilling phase. The drill parameter includes at least one of drill rotational speed, drill torque or number of drill retractions. The program instructions further cause the processor to carry out the step of determining whether the monitored drill parameter is within a predetermined specification for the monitored drill parameter in order to choose a drilling phase defect mitigation routine. After implementing the drilling phase defect mitigation routine, the processors carry out the step of resuming the drilling phase.

Abstract: Various logging-while-drilling (LWD) systems and methods provide resistivity logging coupled with deep detection of elongated anomalies at acute angles, enabling effective geosteering without disrupting drilling operations and without requiring intervention in the operations of the existing well. One LWD system embodiment employs a tool having tilted antennas as the transmitter and the receiver, where at least one of the antennas is placed in the vicinity of the bit, making it possible to detect existing wells at distances of 50-100 feet. In some cases, the detection distance is increased by enhancing the visibility of the existing well using a contrast fluid treatment on target well, either to fill the bore or to surround the well with treated cement or fluids that invade the formation. At least one inversion method separates the inversion of formation parameters from the inversion of parameters specifying distance, direction, and orientation of the existing well.

Abstract: An approach for seismic data analysis is provided. In accordance with various embodiments, the active learning approaches are employed in conjunction with an analysis algorithm that is used to process the seismic data. Algorithms that may employ such active learning include, but are not limited to, ranking algorithms and classification algorithms.

Abstract: Systems and methods for well-drilling operations involving magnetic ranging with a rotating magnetic dipole are provided. In one embodiment, a system for determining a relative location of a magnetic dipole includes a three-axis magnetometer configured to obtain measurements of a time-dependent magnetic field caused by the magnetic source rotating about an axis and data processing circuitry configured to determine a transverse angle of rotation of the measurements such that one of two transverse components is in phase with one axial component when the transverse angle of rotation is used to transform the measurements. The data processing circuitry may determine a spatial relationship between the magnetic source and the three-axis magnetometer based at least in part on the transverse angle of rotation.

Abstract: A method for calculating orientation changes within a borehole using a gyro sensor to detect angular deflection rates in an attitude reference interval as a MWD system is moved from a first to a second location within the borehole. A compass shot may be taken at one or more of the first and second locations using a magnetometer and accelerometer or gyro sensor and accelerometer. Tieback and/or overlap processing may be applied to increase the accuracy of measured orientation within the borehole. Additionally, tieback and/or overlap processing may be applied to adjust sensor model parameters in response to discrepancies between calculated and measured locations. Iterated calculations of orientation change between subsequent intervals may allow MWD orientation to be computed for an entire drilling operation using only a single compass shot.

Abstract: An integrated digital ecosystem comprises an applied fluid optimization specialist and one or more sensors communicatively coupled to the applied fluid optimization specialist. The applied fluid optimization specialist receives data relating to performance of subterranean operations from the one or more sensors and interprets the data received. The applied fluid optimization specialist then regulates the performance of subterranean operations based on the interpretation of the data received.

Abstract: A method for gas analysis can include continuously diverting a portion of drilling fluid into a sample chamber from a drilling fluid stream, creating a bidirectional drilling fluid circulation to liberate gas from the drilling fluid, applying a suction to a gas capturing chamber, and allowing a sample of the liberated fluid to continuously flow through the gas capturing chamber, continuously be filtered, and continuously flow into a gas analyzer. The method can include maintaining the sample chamber in an open configuration or decompressing the gas capturing chamber by closing off one or more sample inlets and sample outlets and exhausting portions of the liberated fluid that do not flow to the gas analyzer. The method can include simultaneously providing analysis data to client devices.

Abstract: A method and detector for detecting a global positioning system (GPS) carrier phase (CP) cycle slip or correcting the GPS CP cycle slip is disclosed. A GPS CP cycle slip detector can include an integrated CP (ICP) change measurement module, an ICP change prediction module, and a processor. The ICP change measurement module can be configured for generating a measured ICP change of a measured CP of a GPS signal for a time duration. The ICP change prediction module can be configured for determining a predicted ICP change of the GPS signal CP for the time duration using directional position information. The processor can be configured for detecting in near real time a GPS CP cycle slip when the measured ICP change varies from the predicted ICP change by greater than a threshold value.

Abstract: The invention relates to a method of performing production operations of an oilfield having at least one process facility and at least one wellsite operatively connected thereto, each at least one wellsite having a wellbore penetrating a subterranean formation for extracting fluid from an underground reservoir therein. The method steps include receiving a number of steps each from at least one of a number of collaborators, specifying an automated workflow including the number of steps and for generating a first well plan, obtaining first data associated with the production operations, applying the automated workflow to the first data to generate the first well plan, adjusting the production operations based on the first well plan, and modifying at least one of the number of steps based on input from at least one of the number of collaborators to generate an updated automated workflow.

Abstract: The examples described herein relate to methods and apparatus for cleanup prediction and monitoring. A disclosed method of predicting cleanup of a sample fluid obtained by a downhole tool includes drawing the sample fluid into the downhole tool via a probe assembly; measuring optical densities of the sample fluid at a plurality of different respective times; selecting at least some of the measured optical densities as fitting points; identifying one or more inversion parameters; and performing, via a processor, an inversion using the fitting points, the inversion parameters and simulation data to generate data associated with a predicted cleanup of the sample fluid.

Abstract: A method includes performing a directional drilling operation. The method also includes receiving data from one or more sensors, wherein at least one of the one or more sensors output data related to a performance attribute of a downhole component that is from a group consisting of a downhole drilling motor and a rotary steerable tool. The downhole component comprises part of a drill string that is used to perform the directional drilling operation. The performance attribute is selected from a group consisting of rotations per unit of time of the downhole component, operating differential pressure across the downhole component and torque output of the downhole component. The method also includes displaying the data in a graphical and numerical representation on a graphical user interface screen.

Abstract: System, methods and devices for measuring and predicting complex borehole geometries are presented herein. A method is disclosed for determining a trajectory of a borehole that is generated by a drill string. The method includes: receiving data indicative of one or more drilling parameters between at least two survey points; averaging the received data over predetermined increments between the at least two survey points; calculating from at least the averaged data a predicted drill string response for each of the predetermined increments; determining from at least the predicted drill string response a change in inclination and azimuth for each of the predetermined increments; generating a predicted wellbore trajectory from the change in inclination and azimuth; comparing the predicted wellbore trajectory to a measured wellbore trajectory; and, if the comparison is favorable, determining a probable borehole position from the change in inclination and azimuth for each of the predetermined increments.

Abstract: A drilling information system comprises a drilling component having an operating status and a drilling control module communicatively coupled to the drilling component and operable to store data indicating the operating status of the drilling component. A wearable interface is communicatively coupled to the drilling control module and is operable to selectively indicate the operating status of the drilling component.

Abstract: A method of calculating a 3-D geologic model in real time using, as input, 2-D geologic data. The 3-D is used for conducting further drilling operations. The model may be updated in real time using additional measurements obtained during drilling operations.

Abstract: The present disclosure relates to a method to determine a volume of clearance surrounding a wellbore. A logging tool is provided. The logging tool may be disposed on a wireline, a drill string, or a wired drill pipe. A formation property is obtained using the logging tool. The formation property may include a voltage, a bulk resistivity, a horizontal resistivity, a vertical resistivity, a porosity, a permeability, a fluid saturation, an NMR relaxation time, a borehole size, a borehole shape, a borehole fluid composition, an MWD parameter, or an LWD parameter. The maximum depth of investigation into the subsurface formation is determined using a model response and a noise level, and the volume of clearance is determined using the determined maximum depth of investigation. The maximum depth of investigation and volume of clearance may be determined even though no boundary layers are detected.

Abstract: A system and method for real-time data acquisition and presentation of force, position, load, pressures, and movement within a subterranean well pumping system, such as an oil well. Data is gathered using sensors attached to a surface level pump drive and wellhead system. Well structural data and well production data are combined therewith to generate a real-time display of down-hole well operation, including animated graphics of the pump operation, including pump movement, rod and tubing stretch, fluid movement, gas compression, system forces, and fluid pressures. Liquid levels are tested using an acoustic liquid level instrument, and incorporated to improve well performance analysis.

Abstract: A method for optimizing wellbore pipe tripping operation includes entering into a computer parameters related to a maximum safe pipe movement speed within the wellbore along at least one selected depth interval along the wellbore. A maximum safe pipe movement speed is calculated. An actual pipe movement speed is measured along the at least one selected depth interval. In the computer, a display is generated of the measured pipe movement speed along with the maximum safe pipe movement speed over the at least one selected depth interval.

Abstract: A method for monitoring condition of a wellbore includes initializing a value of at least one parameter having a relationship to likelihood of a drill string becoming stuck in a wellbore (the HCF). During drilling operations, at least one drilling parameter having a determinable relationship to the HCF is measured. In a computer, the value of the HCF is recalculated based on the at least one measured parameter. The initial value of the HCF and the recalculated values of the HCF are displayed to a user.

Abstract: A method for optimizing drilling includes initializing values of a plurality of drilling operating parameters and drilling response parameters. In a computer, an initial relationship between the plurality of drilling operating parameters and drilling response parameters is determined. A drilling unit to drill a wellbore through subsurface formations. The drilling operating parameters and drilling response parameters are measured during drilling and entered into the computer. A range of values and an optimum value for at least one of the drilling response parameters and at least one of the drilling response parameters is determined in the computer. A display of the at least one of the plurality of drilling operating parameters and the at least one of the drilling response parameters is generated by the computer.

Abstract: A computing device configured to determine when an alarm is triggered for a drilling operation is provided. Measured drilling data that includes a value measured for an input variable during a previous connection event of a drilling operation is received. A predicted value for a fluid flow back measure is determined by executing a predictive model with the measured drilling data as an input. The predictive model is determined using previous drilling data that includes a plurality of values measured for the input variable during a second drilling operation. The second drilling operation is a previous drilling operation at a different geographic wellbore location than the drilling operation. A fluid flow back measurement datum determined from sensor data is compared to the determined predicted value for the fluid flow back measure. An alarm is triggered on the drilling operation based on the comparison.

Abstract: The present disclosure relates to a method to calibrate logging measurements from a logging tool for which one or more attributes vary over the course of logging. A logging tool is provided and a pre-logging calibration function for the logging tool is obtained. Logging measurements are made using the logging tool, and a post-logging calibration function for the logging tool is obtained. A variable calibration function using the pre-logging calibration function and the post-logging calibration function is determined, and the logging measurements are calibrated using the variable calibration function. The variable calibration function may be discrete or continuous and linear or non-linear. A non-linear calibration function may be based on measurements of one or more of the varying attributes of the logging tool. A discrete calibration function may have three or more calibration factors.

Abstract: Techniques for estimating velocity ahead of a drill bit include generating seismic waves at a surface from at least two different source positions in the vicinity of a borehole, receiving seismic waves reflected from a reflector ahead of the drill bit at one or more locations in the borehole, determining travel times of the seismic waves received at the one or more locations in the borehole, and inverting the travel times to determine a velocity of a formation ahead of the drill bit. One embodiment includes transforming the velocity into pore pressure of the formation.

Abstract: A system and computer assisted method to fractionate an oil or other well using a user moveable and rotatable three dimensional model of a lateral pay zone for a directionally drilled well, and other information relative to the lateral pay zone, enabling accurate identification of fractionation zones, accurate placement of well perforating guns, and accurate insertion of fractionation plugs to maximize production of the well, while additionally enabling the three dimensional model of the lateral pay zone to be viewable and updatable by on site uses at the location of the fractionation and by remote users as events occur, in some cases, in providing updates in less than 1 minute.

Abstract: A drilling system and associated systems and methods for monitoring, controlling, and predicting vibration of a drilling operation. The vibration information can include axial, lateral or torsional vibration of a drill string.

Abstract: A method of determining movement dynamics of a drillstring is provided that includes the steps of calculating or measuring a friction coefficient for the sliding contact between the drillstring and the sidewall of a borehole, the friction coefficient being a varying function of non-zero sliding velocities; and predicting movement dynamics of the drillstring using the measured friction coefficient.

Abstract: A method of determining an optimal value for a control of a drilling operation is provided. Drilling data from a drilling operation is received. The drilling data includes a plurality of values measured for each of a plurality of drilling control variables during the drilling operation. An objective function model is determined using the received drilling data. The objective function model maximizes a rate of penetration for the drilling operation. Measured drilling data is received that includes current drilling data values for a different drilling operation. An optimal value for a control of the different drilling operation is determined by executing the determined objective function model with the measured drilling data that includes the current drilling data values for the different drilling operation as an input. The determined optimal value for the control of the different drilling operation is output.

Abstract: There is disclosed a method for assessing risk associated with drilling a section of a wellbore in a formation using a drilling system, comprising: providing a probabilistic model for the risk of the drilling system triggering a failure mode during drilling; and assessing the risk of the drilling system triggering one of said failure modes during drilling of the section based on said model. A further such method comprises: defining the critical control parameters for the drilling system; and identifying one or more failure modes of the drilling system associated with each critical control parameter which may arise during drilling the section of the formation.

Abstract: A method of guiding a probe (20) to a target includes placing a magnetic field generator at the target and guiding the probe (20) to a region of the target. The probe carries a survey sensor pack (28) and the method includes using the survey sensor pack (28), firstly, to obtain a plurality of survey readings and, secondly, to obtain a plurality of magnetic beacon readings using a magnetic field generated by the magnetic field generator. A selected number of the survey readings and the magnetic beacon readings are compared and a difference between the survey readings and the magnetic beacon readings is determined. The method includes compensating for that difference thereafter to guide the probe (20) to the target.

Abstract: A simulation system for marine operator training for operation of a floating oil and gas drilling or production facility or platform, or similar marine facilities. The simulation environment combines a process model with equipment coordinates to calculate center-of-gravity, a ballast and bilge model, an emulation or copy of a field control system, actual Distributed Control System (DCS) operator screens, and a load management advisory program.

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: Methods and systems for characterizing a formation are disclosed. A tool is placed in the formation. The tool comprises a perpendicular antenna set and a parallel antenna set. The perpendicular antenna set comprises at least one transmitter antenna oriented perpendicular to at least one receiver antenna and the parallel antenna set comprises at least one transmitter antenna oriented parallel to at least one receiver antenna. Data is obtained from the tool and used to determine a compensated geosignal for each of the perpendicular antenna set and the parallel antenna set. The determined compensated geosignal is used to characterize the formation.

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: Mud pulse telemetry. The various embodiments are directed to methods and systems of encoding data in a mud pulse telemetry system, where at least a portion of the data is encoded the time between pressure transitions. Moreover, the various embodiments are directed to detection methods and systems that detect the pressure transitions at the surface.

Abstract: Method for determining one or more optimal well trajectories and a drill center location for hydrocarbon production. A well path and drill center optimization problem (55) is solved in which one constraint is that a well trajectory must intersect a finite size target region (61) in each formation of interest, or in different parts of the same formation. The finite target size provides flexibility for the optimization problem to arrive at a more advantageous solution. Typical well path optimization constraints are also applied, such as anti-collision constraints and surface site constraints (62).

Abstract: A system for providing geological trends and real time mapping of a geological basin. The system provides in real time, information from a mass spectrometer on fluid samples from a wellbore, and forms a geochemical surface well log with graphical tracks. The system uses a dataset that includes geochemical, engineering, and geological information. The geochemical surface well log is viewable on a client device connected to a network. The geochemical well log provides information on well fluids and rocks, and displays data in graphical tracks. The mass spectrometer receives samples from a total hydrocarbon analyzer or a gas trap connected to the wellbore. The mass spectrometer performs analysis on fluid samples, and communicates in real time to the geochemical surface well log.

Abstract: A method for providing geological trends and real time mapping of a geological basin by forming a geochemical surface well log. The method provides in real time, information from a mass spectrometer on fluid samples from a wellbore, into a geochemical well log template using computer instructions to create a plurality of graphical tracks. The dataset includes geochemical, engineering, and geological information. The geochemical surface well log is transmitted to and viewable on a client device. The geochemical surface well log provides information on well fluids and rock. The mass spectrometer receives fluid samples and performs analysis on the fluid samples, and then communicates fluid testing data 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: Disclosed is a method implemented by a processor for imaging a formation penetrated by a borehole. The method includes: obtaining acoustic data in a depth-time domain using an acoustic downhole tool disposed at a depth in the borehole, the acoustic downhole tool having an acoustic source and an acoustic receiver; transforming the acoustic data in the depth-time domain into a Radon domain using a Radon transform; filtering the acoustic data in the Radon domain to increase a signal of interest in the acoustic data in the Radon domain; determining a location of a point in the formation that reflected acoustic energy emitted from the acoustic source to the acoustic receiver, the location of the point being represented in the Radon domain; and inverting the location of the point represented in the Radon domain into a radius-depth domain to image the formation.

Abstract: Mud pulse telemetry. The various embodiments are directed to methods and systems of encoding data in a mud pulse telemetry system, where at least a portion of the data is encoded the time between pressure transitions. Moreover, the various embodiments are directed to detection methods and systems that detect the pressure transitions at the surface.

Abstract: A method of drilling a subterranean well from a surface location. The method comprises estimating a target formation depth, estimating a target formation dip angle and calculating a target line that creates a top and bottom of the target formation that forms a first projection window. The method further includes drilling within the first projection window, transmitting information from the subterranean well and projecting a target deviation window. The method may further comprise ceasing the drilling of the well and performing a well survey so that well survey information is generated. The method may then include estimating a formation dip angle with the well survey information and rig surface equipment monitoring data, calculating a target line that creates a revised top and bottom of the target formation that forms a second projection window, and drilling within the second projection window.

Abstract: A method and system for producing look-ahead profiles measurements includes positioning an energy transmitter, such as a transmitting antenna, proximate to a borehole assembly tool. One or more energy receivers, such as receiving antennas, are positioned along a length of the borehole assembly. Next, energy is transmitted to produce look-ahead scans relative to the borehole assembly tool. Look-ahead graph data with an x-axis being a function of a time relative to the position of the borehole assembly tool is generated. The look-ahead graph is produced and displayed on a display device. The look-ahead graph may track estimated formation values based on earth models. The estimated formation values are displayed below a tool position history line that is part of the look-ahead graph. The estimated formation values in the look-ahead graph may be based on inversions of resistivity data from the look-ahead scans.

Abstract: This disclosure relates to apparatuses and methods for reducing current leakage between a measure electrode and a logging tool body during borehole investigations in an earth formation involving electric current and non-conductive drilling fluid. The apparatus may include one or more transmitters disposed on a pad body, configured to inject an electric current into the earth formation, and coupled to the mandrel and one or more measure electrodes. The measure electrodes may be configured to receive current from the formation and coupled to a back plate of the pad body. The apparatus may be configured to maintain a selected ratio between pad body to logging tool body impedance and transmitters to logging tool body impedance sufficient to reduce current leakage between the earth formation and the logging tool body. The transmitter/mandrel and measure electrode/back plate may be electrically isolated from one another. The method may include using the apparatus.

Abstract: Systems and methods for determining the bending moment and shear force of tubing and casing when the tubing buckles and contacts the casing.

Abstract: Various techniques for generating a polar display include a method, which involves receiving information identifying a formation property of an anomaly within a geologic formation from a measurement-while-drilling (MWD) tool that includes several sensors. The formation property is identified by at least one magnitude and at least one distance. The formation property is also identified relative to a corresponding property of the geologic formation. The method also involves receiving information identifying an azimuthal angle from the MWD tool, where the azimuthal angle relates a position of the anomalous formation to a position of a first sensor. The method then generates a graphic, based upon the at least one magnitude and the at least one distance and the azimuthal angle, and displays the graphic on a polar display, in which a center of the polar display corresponds to a location of the borehole in which the MWD tool is located.

Abstract: A system for creating a log during gas detection and monitoring is disclosed herein. The system can include a gas detection and well logging device for sensing and transmitting data, which can include a processor in communication with a monitoring device. The monitoring device can monitor, acquire, and transmit data associated with a drilling operation. The processor can receive the data, calibrate the data, and log the data into files. The processor can capture sensed data based on a time event and a depth event. The processor can scale the data and form a geological-hydrocarbon log for transmission. A client device can be in communication with the gas detection and well logging device, and can have computer instructions for querying the geological hydrocarbon log, the data, and the files to obtain real time streaming data for instant display.

Abstract: A system and method for monitoring underground drilling in which vibration is monitored by creating a model of the drill string using finite element techniques or finite difference techniques and (i) predicting vibration by inputting real time values of operating parameters into the model, and then adjusting the model to agree with measured vibration data, (ii) predicting the weight on bit and drill string and mud motor speeds at which resonance will occur, as well as when stick-slip will occur, so that the operator can avoid operating regimes that will result in high vibration, (iii) determining vibration and torque levels along the length of the drill string based on the measured vibration and torque at one or more locations, (iv) determining the remaining life of critical components of the drill string based on the history of the vibration to which the components have been subjected, and (v) determining the optimum drilling parameters that will avoid excessive vibration of the drill string.

Abstract: A system for determining the amount of life consumed for a tool includes at least one sensor associated with the tool for generating observation data, a memory in operable communication with the at least one sensor, the memory including a database for storing the observation data generated by the sensor, and a processor in operable communication with the memory. The processor includes a model generator that generates a current model for a current run of the tool. The current model includes parameters of a functional approximation of the observation data. The processor also includes a classifier that classifies the current model and a current run estimator that determine the amount of life consumed based on the classification of the current model and a time of use associated with the current run.

Abstract: A system, method and computer-readable medium for a drilling a borehole is disclosed. Errors associated with multi-station survey measurements are obtained and partitioned into a set of estimated errors and a set of considered errors. A post-fit covariance matrix is determined from the estimated errors and includes the effects of the considered errors on the estimated errors. A drilling parameter of a drill string in the borehole may be altered using the determined post-fit covariance matrix.

Abstract: Disclosed are systems and methods for automatic weight on bit sensor calibration and regulating buckling of a drillstring. One method includes taking a first survey recording at a first depth within a borehole, the first survey recording providing inclination and azimuth of a drillstring at the first depth, measuring a weight on a drill bit at the first depth with a sensor sub arranged on a bottom hole assembly, the bottom hole assembly forming part of the drillstring and the drill bit being disposed at an end of the drillstring, calculating a predicted borehole curvature at a second depth within the borehole, the predicted curvature including a predicted inclination and a predicted azimuth of the drillstring at the second depth, calculating a weight correction value based on the predicted hole curvature, and calibrating the sensor sub with the weight correction value.