Schlumberger Technology Corporation

Cameron International Corporation

Sensia LLC

David J Rossi

Omer M Gurpinar

Philip W Pantella

Vidya B Verma

Nicolas Arteaga

Min-Yi Chen

Kamal Babour

Terizhandur S Ramakrishnan

Francois M Auzerais

Nam H Nguyen

Albert Hoefel

Christian Chouzenoux

Ian D Bryant

Willem Albert Wijnberg

Elizabeth B Dussan V

Jean-Pierre R Delhomme

Peter Allan Goode

Peter V Howard

William F Murphy

Carlos Torres-Verdin

Taylor Mozisek

Fikri Kuchuk

Yogesh S Dave

Alberto Malinverno

Michael P Ekstrom

T S Ramakrishnan

Supriya Gupta

Jonathan Wun Shiung Chong

Orhan Arikan

Pengyu Yuan

Oscar B Jones

Allen Q Howard, Jr

Metin Karakas

Rod Nelson

Marcus Suzart Ungaretti Rossi

Brian Spies

James Helwig

Peter Goode

Richard Plumb

Miguel Angel Hernandez De La Bastida

Michael Van Spankeren

James J Flynn

T Everett Chambliss

Andrew Acock

Werner Menz

A system for oil and gas production includes a drilling, pipeline, or power quality device, a sensor, and a storage device. The storage device has instructions stored thereon that, when executed by one or more processors, cause the one or more processors to perform operations. The operations include receiving first data from the sensor. The operations include determining whether the device is experiencing an event condition based on the first data The operations include generating one or more potential corrective actions responsive to a determination that the device is experiencing the event condition. The operations include calculating a reward value for each of the one or more potential corrective actions. The operations include identifying a first corrective action of the one or more potential corrective actions with a largest or most positive reward value The operations include controlling the device according to the first corrective action.

Event driven control schemas for artificial lift

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.

Chemical injection system for a resource extraction system

Techniques for detecting and correcting for discrepancy events in a fluid pipeline are presented. The techniques can include obtaining a plurality of empirical temperature and pressure measurements at a plurality of locations within the pipeline; simulating, using a pipeline model, a plurality of simulated temperature and pressure measurements for the plurality of locations within the pipeline; detecting, by a discrepancy event detector, at least one discrepancy event representing a discrepancy between the empirical temperature and pressure measurements and the simulated temperature and pressure measurements; outputting to a user an indication that the at least one discrepancy event has been detected; accounting for the at least one discrepancy; determining, after the accounting and using an estimator applied to the pipeline model, a corrected branch flow rate for the pipeline; and outputting the corrected branch flow rate for the pipeline to the user.

Detecting and correcting for discrepancy events in fluid pipelines

An annular elastomeric packer for a blowout preventer includes a first insert including an upper flange extending between a radially inner end and a radially outer end, a lower flange extending between a radially inner end and a radially outer end, and a rib extending between the upper flange and the lower flange, wherein the rib includes a length extending between an upper end and a lower end of the rib, a second insert including an upper flange extending between a radially inner end and a radially outer end, a lower flange extending between a radially inner end and a radially outer end, and a rib extending between the upper flange and lower flange, wherein the rib includes a length extending between an upper end and a lower end of the rib, an elastomeric body coupled to the first insert and the second insert, and including an inner sealing surface.

Blowout preventer systems and methods

A blowout preventer ('BOP') includes a housing comprising a vertical bore extending through the housing and a packer assembly movably positioned within the housing and configured to form a seal within the housing. The packer assembly includes an elastomeric body comprising an elastomeric material and inserts positioned within the elastomeric body and in parallel alignment with respect to each other.

Packer assembly with inserts for blowout preventer

Embodiments of the present disclosure include a method that includes creating a deterministic model representing a production system. The model may include one or more inputs and parameters that are not deterministically known, and one or more outputs. A prior probability density function may be used to determine a prior uncertainty, and a measurement related to a first of the outputs may be obtained. The method may also include determining a posterior probability density function using the prior probability density function, the measurement, and a conditional probability density function. Embodiments of the present disclosure also include a computer-readable medium having a set of computer-readable instructions residing thereon that, when executed, perform acts comprising the foregoing method. Embodiments of the present disclosure further include a computing device that includes a memory, one or more processors operatively coupled to the memory, and functionality operable by the processors to perform the foregoing method.

Method, system and apparatus for modeling production system network uncertainty

A method of managing a fluid or gas reservoir is disclosed which assimilates diverse data having different acquisition time scales and spatial scales of coverage for iteratively producing a reservoir development plan that is used for optimizing an overall performance of a reservoir. The method includes: (a) generating an initial reservoir characterization, (b) from the initial reservoir characterization, generating an initial reservoir development plan, (c) when the reservoir development plan is generated, incrementally advancing and generating a capital spending program, (d) when the capital spending program is generated, monitoring a performance of the reservoir by acquiring high rate monitor data from a first set of data measurements taken in the reservoir and using the high rate monitor data to perform well-regional and field-reservoir evaluations, (e) further monitoring the performance of the reservoir by acquiring low rate monitor data from a second set of data measurements taken in the reservoir, (f) assimilating together the high rate monitor data and the low rate monitor data, (g) from the high rate monitor data and the low rate monitor data, determining when it is necessary to update the initial reservoir development plan to produce a newly updated reservoir development plan, (h) when necessary, updating the initial reservoir development plan to produce the newly updated reservoir development plan, and (i) when the newly updated reservoir development plan is produced, repeating steps (c) through (h). A detailed disclosure is provided herein relating to the step (a) for generating the initial reservoir characterization and the step (b) for generating the initial reservoir development plan.

Integrated reservoir optimization

The invention relates to a method of performing a numerical model study to accurately forecast a production of a well in a reservoir. The method involves determining a property distribution of the reservoir using a three dimensional (3D) structure and property model for providing an estimate of a 3D structure, wherein the estimate of the 3D structure includes the property distribution, determining a grid system, including a grid and layering mechanism that is superimposed on said 3D structure and said property distribution associated with the digital 3D structure and property model, using a 3D simulator grid system, and determining a rock model using an initial 3D reservoir simulator in response to the estimate of the property distribution associated with the digital 3D structure and property model and the grid system associated with the 3D simulator grid system, wherein the rock model is used to accurately forecast the production of the well in the reservoir.

A method and associated apparatus continuously optimizes reservoir, well and surface network systems by using monitoring data and downhole control devices to continuously change the position of a downhole intelligent control valve (ICV) () until a set of characteristics associated with the 'actual' monitored data is approximately equal to, or is not significantly different than, a set of characteristics associated with 'target' data that is provided by a reservoir simulator (). A control pulse () having a predetermined signature is transmitted downhole thereby changing a position of the ICV. In response, a sensor () generates signals representing, &#x201c;actual&#x201d; monitoring data. A simulator () which models a reservoir layer provides &#x201c;target&#x201d; data. A computer apparatus () receives the &#x201c;actual&#x201d; data and the &#x201c;target&#x201d; data and, when the &#x201c;actual&#x201d; data is not approximately equal to the &#x201c;target&#x201d; data the computer apparatus () executes a &#x201c;monitoring and control process&#x201d; program code which changes the predetermined signature of the control pulse to a second and different predetermined signature. A new pulse having the second predetermined signature is transmitted downhole and the above process repeat until the &#x201c;actual&#x201d; data received by the computer apparatus () is approximately equal to the &#x201c;target&#x201d; data.

Optimization of reservoir, well and surface network systems

A system that is usable with a subterranean well that has a casing includes an apparatus that is associated with production of fluid from the well and is located downhole in the well in a passageway of the casing. The system also includes a sensor that is located downhole near the apparatus in the passageway and is adapted to measure a characteristic of the formation fluids and rock located outside of the casing.

Downhole measurement apparatus and technique

Intergrated reservoir optimization

An apparatus and method is presented for establishing electrical connection to permanent downhole oilfield installations using an electrically insulated conducting casing. Current is caused to flow in the casing by a source on the surface connected to the casing. One or more permanent downhole installations are electrically connected to the casing, and the electrical connection to the casing is used to power the downhole installations. The downhole installations also inject a signal into the insulated casing that passes via the casing to a surface readout which detects and records the downhole signals.

Power and signal transmission using insulated conduit for permanent downhole installations

Sensors are permanently placed in the ground near observation and injection wells in order to passively and continuously monitor the status of seawater advance toward fresh water aquifers near coastal cities as well as the status of fresh water injected into the injection wells. Such sensor devices are installed in the ground and electrically connected to surface acquisition equipment that would, without human intervention, transmit acquired data to a centralized facility for processing and interpretation. Various types of sensors can be used: the sensors used for general reservoir monitoring and/or the sensors used for leak detection, soil heating, and temperature mapping. Alternatively, a special type of sensor can be designed and provided for the purpose of monitoring the status of seawater advance toward fresh water aquifers.

Method and apparatus for monitoring the advance of seawater into fresh water aquifers near coastal cities

Methods for locating an oil-water interface in a petroleum reservoir include taking resistivity and pressure measurements over time and interpreting the measurements. The apparatus of the invention includes sensors preferably arranged as distributed arrays. According to a first method, resistivity and pressure measurements are acquired simultaneously during a fall-off test. Resistivity measurements are used to estimate the radius of the water flood front around the injector well based on known local characteristics. The flood front radius and fall-off pressure measurements are used to estimate the mobility ratio. According to a second method, resistivity and pressure measurements are acquired at a variety of times. Prior knowledge about reservoir parameters is quantified in a probability density function (pdf). Applying Bayes' Theorem, prior pdfs are combined with measurement results to obtain posterior pdfs which quantify the accuracy of additional information. As new measurements are acquired, posterior pdfs, updated for expected temporal variations, become prior pdfs for the new measurements. According to a third method, uncertainty about the reservoir parameters is represented by Gaussian pdfs. The relationship between measurements and reservoir parameters is locally approximated by a linear function. Uncertainties are quantified by a posterior covariance matrix.

Methods and apparatus for dynamically estimating the location of an oil-water interface in a petroleum reservoir

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Newtown, CT, United States of America

David J Rossi