Patent Grant
12221883
A coreflood test is conducted in a laboratory and a fluid or combination of fluids is injected into a sample of rock to observe interactions between the fluid and the rock. The core material comes from an oil reservoir, an outcrop rock, or other rock. Test conditions may be conducted at ambient temperature and low confining pressure or at high temperature and pressure to match that of a subject reservoir. Pressures and flow rates at both ends of the core are measured. The injected fluids may include chemicals used in the oil field. A coreflood is typically used to determine the optimum development option for an oil reservoir and often helps evaluate the effect of injecting fluids specially designed to improve or enhance oil recovery.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
This disclosure presents, in accordance with one or more embodiments, a method that includes acquiring a core sample from a first reservoir of interest that is producing hydrocarbons at a first recovery rate, the performing a coreflooding study using a core flood apparatus. The coreflooding study includes a plurality of coreflooding simulations using the core sample disposed in the core flood apparatus. The method includes a control system automatically performing a reservoir simulation study on the first reservoir using a coreflooding simulation model and using the coreflooding study. The method includes a control system automatically adjusting a core flood fluid based on the reservoir simulation study to form an adjusted treatment fluid that produces a second recovery rate from the first reservoir. The second recovery rate is greater than the first recovery rate. The method includes using an injection well and the adjusted treatment fluid and performing an injection operation of a reservoir.
This disclosure presents, in accordance with one or more embodiments, an apparatus that includes a confining chamber defined by a chamber inner wall of a core holder body, a conformable sleeve, a core end plug sealingly coupled to the core holder body and to the conformable sleeve, and a second end cap sealingly coupled to the core holder body. The core end plug is configured to couple to a sleeve first end of the conformable sleeve. The conformable sleeve is configured to hold a core sample from a first reservoir of interest such that a core outer surface-surface contact is formed with a sleeve inner surface and a core outer surface. The conformable sleeve includes a core piston configured for a sliding fit within the conformable sleeve. The core piston is inserted into the conformable sleeve from a sleeve second end such that a core end surface-surface contact is formed with a core piston surface. The apparatus includes a fluid cell defined by a cell inner wall of a cell body and a first end cap configured to sealingly couple to the cell body. The fluid cell is configured to sealingly couple to the confining chamber. The apparatus includes a piston translatably disposed in the fluid cell and configured to sealingly divide the fluid cell into a treatment fluid cell and a hydraulic chamber. The apparatus includes a translatable tube coupled to the core piston and configured for a sealing fit between the translatable tube and the second end cap. The apparatus includes a monitoring subsystem coupled to the confining chamber, the hydraulic chamber, and the treatment fluid cell. The monitoring subsystem is configured for recording coreflooding simulation data. The apparatus includes a communication interface coupled to the monitoring subsystem. The apparatus includes a processor coupled to the monitoring subsystem and the communication interface. The apparatus includes and a memory coupled to the processor. The memory includes instructions configured to perform a method including: obtain a command to generate the coreflooding simulation data; generate the coreflooding simulation data; and transmit the coreflooding simulation data using the communication interface.
This disclosure presents, in accordance with one or more embodiments, a system that includes a core flood apparatus including a core holder, a communication interface, a processor, and a memory. The core flood apparatus is configured for holding, using the core holder, a core sample acquired from a first reservoir of interest. The first reservoir is producing hydrocarbons at a first recovery rate. The system includes a control system coupled to the core flood apparatus. The control system includes a computer processor. The control system includes functionality for a method that includes performing, by the core flood apparatus, a coreflooding study including a plurality of coreflooding simulations using the core sample disposed in the core flood apparatus. The method includes performing, by the control system and using a coreflooding simulation model, a reservoir simulation study on the first reservoir using the coreflooding study. The method includes adjusting, by the control system, a core flood fluid based on the reservoir simulation study to form an adjusted treatment fluid that produces a second recovery rate from the first reservoir. The second recovery rate is greater than the first recovery rate. The method includes performing, using an injection well, an injection operation of a reservoir using the adjusted treatment fluid. The communication interface is configured to transmit coreflooding simulation data to the control system and the memory is configured to store the coreflooding simulation data.
In light of the structure and functions described above, embodiments disclosed herein may include respective means adapted to carry out various steps and functions defined above in accordance with one or more aspects and any one of the embodiments of one or more aspect described herein.
Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.
Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency.
In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.
Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.
Regarding the figures described herein, when using the term “down” the direction is toward or at the bottom of a respective figure and “up” is toward or at the top of the respective figure. “Up” and “down” are oriented relative to a local vertical direction. In the oil and gas industry, one or more activities take place in a vertical, substantially vertical, deviated, substantially horizontal, or horizontal well. Therefore, one or more figures may represent an activity in deviated or horizontal wellbore configuration. “Uphole” may refer to objects, units, or processes that are positioned relatively closer to the surface entry in a wellbore than another. “Downhole” may refer to objects, units, or processes that are positioned relatively farther from the surface entry in a wellbore than another. Measured depth (MD) is the length of the wellbore. True vertical depth (TVD) is the vertical distance from a point in the well at a location of interest to a reference point on the surface.
A producing zone of a reservoir is the zone containing hydrocarbons that are economically producible. The reservoir is marked with geological markers to drill the wellbore into the producing zone for optimal production and reservoir coverage. The geological layers may be characterized by the angle of the geological layers. Core samples may be acquired to characterize the geological and geophysical parameters in a coreflooding study. The parameters may be used to determine a treatment fluid such as an injection fluid for use in producing from the well using techniques such as waterflooding, enhanced oil recovery (EOR), and formation damage mitigation.
A coreflooding study is one of many crucial methods to evaluate, in a laboratory setting, each of many candidate injection fluids, i.e., test fluids or core flood fluids. The coreflooding study investigates an interaction between a core flood fluid and a core sample. The interaction may be affected by several test factors such as environmental parameters (e.g., pressure, temperature), core sample parameters (e.g., porosity), and core flood fluid parameters (e.g., chemical formulation or chemical blend, injection pressure.) The study detects the interaction and compares the interaction with a desired outcome, e.g., a predetermined criterion of a set of predetermined criteria. The comparison result may be that the interaction satisfies the predetermined criteria (or a criterion of the criteria). The result may be that the interaction fails to satisfy the predetermined criterion.
Depending on the results of the comparison the test factors may be adjusted. For example, the control system may determine whether a first coreflooding simulation satisfies a predetermined criterion. If the first coreflooding simulation fails to satisfy the predetermined criterion, then the control system may determine replacement simulation parameters for the coreflooding simulation test. For example, for a predetermined reservoir, the rock characteristics, the downhole pressure, and the downhole temperature are functions of the reservoir and may not be adjustable. The chemical formulation of the treatment fluid may be adjusted to evaluate its performance by observing its interaction with the rock at the given pressures and temperatures. The injection pressure and flowrate of the treatment fluid may also be adjusted to observe their impacts on the interactions and thus the performance. Together the core fluid parameters of formulation, pressure, and flowrate may be adjusted and the test repeated. The test may be terminated if the interaction does not meet the predetermined criteria, i.e., if the coreflooding simulation fails to satisfy the predetermined criterion.
The coreflooding study may investigate the interaction within a core flood apparatus containing the core flood fluid and the core sample. The core flood apparatus may be disposed in a core flood study system (e.g., a coreflooding system) used for performing the coreflooding study. The coreflooding system may include the core flood apparatus and various computer systems, computer processors, sensors, electrical power supplies, electrical wiring harnesses, pumps, fluids, and plumbing. The various components of the coreflooding system may be subjected to environmental conditions such as heating and cooling using, for example, a heating jacket or a cooling sleeve.
The coreflooding study provides essential input for development designs and performance predictions. For instance, a chemical flooding project may start with a series of laboratory studies to screen some candidate formulations of candidate injection fluids. Each candidate injection fluid may be tested one or more times. The candidate injection fluid, i.e., a core fluid, used for each test is known as a test fluid. Coreflooding studies, injecting test fluids to the core samples from a target reservoir, is then performed to validate and optimize the formulas in core scale. The experimental results provide essential input parameters for numerical reservoir simulation studies, which are employed to evaluate the field-scale performance and optimize injection strategies. Finally, the optimized formula is then deployed for field application. Examples of commonly conducted coreflooding studies are waterflooding, enhanced oil recovery (EOR), and formation damage evaluations.
The coreflooding experiment is conducted to simulate the fluid flow through reservoir formations using representative core samples. It usually requires a complex coreflooding system for the test, and it is time consuming to conduct the coreflooding experiment. Some projects may even require many coreflooding tests for evaluating injection fluids or providing essential data. Sometimes, it is also a challenge to obtain adequate sample size, or to prepare a regular cylindrical shape. A simplified method to study the fluid flow through porous media is to perform the test using fabricated micromodels (or microfluidic chips). However, the porous media involved in these tests are far from representative of the pore systems of actual reservoir rocks. Thus, it is desirable to conduct the core flood tests using more convenient setup and smaller core samples than the conventional tests.
In general, embodiments of the disclosure include systems and methods for a compact apparatus using smaller core sample for rapid coreflooding evaluation tests. There is a need for rapid evaluation of injection fluids for oil recovery potentials in the petroleum industry. There are some cases of oilfield developments for conventional corefloods in which there are no adequate sizes of core or there is no adequate amount of test fluid, e.g., a candidate treatment fluid. Micromodel tests are an option for evaluating treatment fluids, but are mainly used for observing the mechanisms of fluid flow in porous media, and the two-dimensional porous media are far less representative of reservoir rocks.
The conventional coreflooding tests require complicated setups including, in a conventional coreflooding test system, at least one core holder, several cylinders for injection fluids, many flow control valves all of which are built in a large oven, plus long tubes for pressurization. The long tubes are required for connecting the flow paths, and the tube lengths introduce large dead volumes in the system. The conventional core holders require larger-sized and regular-shaped (conventional shape) core plug samples. Larger volumes of fluids may also be needed when the pore volume of the core is larger. It is time-consuming to conduct coreflooding experiments, especially when a project such as a coreflooding study requires conducting many individual coreflooding tests.
The compact apparatus is a core flood test apparatus (hereafter a test apparatus) that integrates a core sample holder with an injection fluid cell, and the core sample holder can accommodate smaller-sized and irregular-shaped core plug (cylindrical rock) samples In comparison with the conventional coreflooding test system, the test apparatus integrates the core sample holder with the injection fluid cell thereby reducing the quantity of flow control valves and long connecting tubes, thus significantly reducing the dead volumes. In contrast with the conventional coreflooding test system which requires a large oven, the test apparatus may include a heating jacket for temperature control with the heating jacket covering both the core holder and the injection fluid. The test apparatus may help significantly reduce equipment cost as well as working space. In comparison with the conventional coreflooding test system, rock samples used for the tests in the test apparatus can be smaller than the conventional coreflooding tests, while still much larger and more representative than the porous media of micromodels. The smaller-sized core samples can be trimmed from small end pieces of regular cores. Small core pore volumes allow the rapid evaluations. In general, the disclosed test apparatus has the advantages of convenience, rapid evaluation, and cost effectiveness.
The disclosed test apparatus can accommodate smaller-sized and irregular-shaped core samples instead of the larger-sized and regular-shaped core samples used in conventional coreflooding test systems can be used the test apparatus. The commonly used core samples have diameter of 1.5 inches (3.81 cm) or 1.0 inch (2.54 cm) with length longer than 1.0 inch (2.54 cm). The smaller core samples for the test apparatus, for example, can have dimensions of 1.0 cm in diameter and 1.0 cm in length. The small samples can be trimmed from end pieces of core samples when cores of regular sample sizes are not available. As long as the rubber sleeve (e.g., the core sleeve) can hold the core sample, certain irregularity in the core sample can also be accommodated in the test apparatus. Smaller core samples have smaller pore volumes, which help accelerate the evaluation process. For example, fluid injectivity can be conveniently evaluated by injecting large pore volumes of test fluid (e.g., a candidate treatment fluid) to a small core sample. When designing chemical solutions, e.g., a coreflood fluid formula, for improving oil recovery, e.g., to form an optimized treatment fluid, the disclosed system and method may be used to rapidly validate the formulations by evaluating the oil recovery potential using the candidate chemicals.
In some embodiments, the well system 106 includes a wellbore 120, a well sub-surface system 122, a well surface system 124, and a well control system 126. The well control system 126 may control various operations of the well system 106, such as well production operations, well completion operations, well maintenance operations, and reservoir monitoring, assessment, and development operations. In some embodiments, the well control system 126 includes a computer system that is the same as or similar to that of computer system described below in
The wellbore 120 may include a bored hole that extends from the surface 108 into a target zone of the formation 104, such as the reservoir 102. An upper end of the wellbore 120, terminating at or near the surface 108, may be referred to as the “up-hole” end of the wellbore 120, and a lower end of the wellbore, terminating in the formation 104, may be referred to as the “downhole” end of the wellbore 120. The wellbore 120 may facilitate the circulation of drilling fluids during drilling operations, the flow of hydrocarbon (e.g., oil and gas) production (e.g., production 128) from the reservoir 102 to the surface 108 during production operations, the injection of substances (e.g., water) into the formation 104 or the reservoir 102 during injection operations, or the communication of monitoring devices (e.g., logging tools) into the formation 104 or the reservoir 102 during monitoring operations (e.g., during in situ logging operations).
In some embodiments, during operation of the well system 106, the well control system 126 collects and records wellhead data 150 for the well system 106 and other data regarding downhole equipment and downhole sensors (e.g., using an automatic computer-controlled management system described herein.) The wellhead data 150 may include, for example, a record of measurements of wellhead pressure (P) (e.g., including flowing wellhead pressure (FWHP)), wellhead temperature (T) (e.g., including flowing wellhead temperature), wellhead production rate (Q) over some or all of the life of the well system 106, and water cut data. In some embodiments, the measurements are recorded in real-time, and are available for review or use within seconds, minutes or hours of the condition being sensed (e.g., the measurements are available within 1 hour of the condition being sensed). In such an embodiment, the wellhead data 150 may be referred to as “real-time” wellhead data. Real-time wellhead data may enable an operator of the well system 106 to assess a relatively current state of the well system 106, and to make real-time decisions regarding development of the well system 106 and the reservoir 102, such as on-demand adjustments in regulation of production flow from the well.
With respect to water cut data, the well system 106 may include one or more water cut sensors. For example, a water cut sensor may be hardware and/or software with functionality for determining the water content in oil, also referred to as “water cut.” Measurements from a water cut sensor may be referred to as water cut data and may describe the ratio of water produced from the wellbore 120 compared to the total volume of liquids produced from the wellbore 120. In some embodiments, a water-to-gas ratio (WGR) is determined using a multiphase flow meter. For example, a multiphase flow meter may use magnetic resonance information to determine the number of hydrogen atoms in a particular fluid flow. Since oil, gas and water all contain hydrogen atoms, a multiphase flow may be measured using magnetic resonance. In particular, a fluid may be magnetized and subsequently excited by radio frequency pulses. The hydrogen atoms may respond to the pulses and emit echoes that are subsequently recorded and analyzed by the multiphase flow meter.
In some embodiments, the well surface system 124 includes a wellhead 130. The wellhead 130 may include a rigid structure installed at the “up-hole” end of the wellbore 120, at or near where the wellbore 120 terminates at the surface 108. The wellhead 130 may include structures for supporting (or “hanging”) casing and production tubing extending into the wellbore 120. Production 128 may flow through the wellhead 130, after exiting the wellbore 120 and the well sub-surface system 122, including, for example, the casing and the production tubing. In some embodiments, the well surface system 124 includes flow regulating devices that are operable to control the flow of substances into and out of the wellbore 120. For example, the well surface system 124 may include one or more of a production valve 132 that are operable to control the flow of production 128. For example, a production valve 132 may be fully opened to enable unrestricted flow of production 128 from the wellbore 120, the production valve 132 may be partially opened to partially restrict (or “throttle”) the flow of production 128 from the wellbore 120, and production valve 132 may be fully closed to fully restrict (or “block”) the flow of production 128 from the wellbore 120, and through the well surface system 124.
Keeping with
In some embodiments, the surface sensing system 134 includes a surface pressure sensor 136 operable to sense the pressure of production 128 flowing through the well surface system 124, after it exits the wellbore 120. The surface pressure sensor 136 may include, for example, a wellhead pressure sensor that senses a pressure of production 128 flowing through or otherwise located in the wellhead 130. In some embodiments, the surface sensing system 134 includes a surface temperature sensor 138 operable to sense the temperature of production 128 flowing through the well surface system 124, after it exits the wellbore 120. The surface temperature sensor 138 may include, for example, a wellhead temperature sensor that senses a temperature of production 128 flowing through or otherwise located in the wellhead 130, referred to as “wellhead temperature” (T). In some embodiments, the surface sensing system 134 includes a flow rate sensor 140 operable to sense the flow rate of production 128 flowing through the well surface system 124, after it exits the wellbore 120. The flow rate sensor 140 may include hardware that senses a flow rate of production 128 (Q) passing through the wellhead 130.
Keeping with
In one well completion example, the sides of the wellbore 120 may require support, and thus casing may be inserted into the wellbore 120 to provide such support. After a well has been drilled, casing may ensure that the wellbore 120 does not close in upon itself, while also protecting the wellstream from outside contaminants, like water or sand. Likewise, if the formation is firm, casing may include a solid string of steel pipe that is run in the well and will remain that way during the life of the well. In some embodiments, the casing includes a wire screen liner that blocks loose sand from entering the wellbore 120.
In another well operation example, a space between the casing and the untreated sides of the wellbore 120 may be cemented to hold a casing in place. This well operation may include pumping cement slurry into the wellbore 120 to displace existing drilling fluid and fill in this space between the casing and the untreated sides of the wellbore 120. Cement slurry may include a mixture of various additives and cement. After the cement slurry is left to harden, cement may seal the wellbore 120 from non-hydrocarbons that attempt to enter the wellstream. In some embodiments, the cement slurry is forced through a lower end of the casing and into an annulus between the casing and a wall of the bored hole of the wellbore 120. More specifically, a cementing plug may be used for pushing the cement slurry from the casing. For example, the cementing plug may be a rubber plug used to separate cement slurry from other fluids, reducing contamination and maintaining predictable slurry performance. A displacement fluid, such as water, or an appropriately weighted drilling fluid, may be pumped into the casing above the cementing plug. This displacement fluid may be pressurized fluid that serves to urge the cementing plug downward through the casing to extrude the cement from the casing outlet and back up into the annulus.
Keeping with well operations, some embodiments include perforation operations. More specifically, a perforation operation may include perforating casing and cement at different locations in the wellbore 120 to enable hydrocarbons to enter a wellstream from the resulting holes. For example, some perforation operations include using a perforation gun at one or more reservoir levels to produce holed sections through the casing, cement, and sides of the wellbore 120. Hydrocarbons may then enter the wellstream through these holed sections. In some embodiments, perforation operations are performed using discharging jets or shaped explosive charges to penetrate the casing around the wellbore 120.
In another well completion, a filtration system may be installed in the wellbore 120 in order to prevent sand and other debris from entering the wellstream. For example, a gravel packing operation may be performed using a gravel-packing slurry of appropriately sized pieces of coarse sand or gravel. As such, the gravel-packing slurry may be pumped into the wellbore 120 between a casing's slotted liner and the sides of the wellbore 120. The slotted liner and the gravel pack may filter sand and other debris that might have otherwise entered the wellstream with hydrocarbons. In another well completion, a wellhead assembly may be installed on the wellhead of the wellbore 120. A wellhead assembly may include a production tree (also called a Christmas tree) that includes valves, gauges, and other components to provide surface control of subsurface conditions of a well.
In some embodiments, a wellbore 120 includes one or more casing centralizers. For example, a casing centralizer may be a mechanical device that secures casing at various locations in a wellbore to prevent casing from contacting the walls of the wellbore. Thus, casing centralization may produce a continuous annular clearance around casing such that cement may be used to completely seal the casing to walls of the wellbore. Without casing centralization, a cementing operation may experience mud channeling and poor zonal isolation. Examples of casing centralizers may include bow-spring centralizers, rigid centralizers, semi-rigid centralizers, and mold-on centralizers. In particular, bow springs may be slightly larger than a particular wellbore in order to provide complete centralization in vertical or slightly deviated wells. On the other hand, rigid centralizers may be manufactured from solid steel bar or cast iron with a fixed blade height in order to fit a specific casing or hole size. Rigid centralizers may perform well even in deviated wellbores regardless of any particular side forces. Semi-rigid centralizers may be made of double crested bows and operate as a hybrid centralizer that includes features of both bow-spring and rigid centralizers. The spring characteristic of the bow-spring centralizers may allow the semi-rigid centralizers to compress in order to be disposed in tight spots in a wellbore. Mold-on centralizers may have blades made of carbon fiber ceramic material that can be applied directly to a casing surface.
In some embodiments, well intervention operations may also be performed at a well site. For example, well intervention operations may include various operations carried out by one or more service entities for an oil or gas well during its productive life (e.g., hydraulic fracturing operations, coiled tubing, flow back, separator, pumping, wellhead and production tree maintenance, slickline, braided line, coiled tubing, snubbing, workover, subsea well intervention, etc.). For example, well intervention activities may be similar to well completion operations, well delivery operations, and/or drilling operations in order to modify the state of a well or well geometry. In some embodiments, well intervention operations are used to provide well diagnostics, and/or manage the production of the well. With respect to service entities, a service entity may be a company or other actor that performs one or more types of oil field services, such as well operations, at a well site. For example, one or more service entities may be responsible for performing a cementing operation in the wellbore 120 prior to delivering the well to a producing entity.
Turning to the reservoir simulator 160, a reservoir simulator 160 may include hardware and/or software with functionality for performing a well simulation (e.g., well simulations of the wellbore of one or more wells) such as storing and analyzing well logs, production data, sensor data (e.g., from a wellhead, downhole sensor devices, or flow control devices), and/or other types of data to generate and/or update one or more geological models of one or more reservoir regions. Geological models may include geochemical or geomechanical models that describe structural relationships within a particular geological region. Likewise, a reservoir simulator 160 may also determine changes in reservoir pressure and other reservoir properties for a geological region of interest, e.g., in order to evaluate the health of a particular reservoir during the lifetime of one or more producing wells.
While the reservoir simulator 160 is shown at a well site, in some embodiments, the reservoir simulator 160 or other components in
In some embodiments, the reservoir simulator 160 may include software configured with machine learning capabilities and artificial intelligence (AI) that learn from trends of the one or more parameters tracked by the well control system 126.
In one or more embodiments, the AI and machine learning (ML) capabilities employed by the reservoir simulator may include any suitable algorithms and processes for predicting well behavior using historical data as input. For example, the machine-learning models (ML models) or algorithms may include supervised algorithms, unsupervised algorithms, deep learning algorithms that use artificial neural networks (ANN), etc. More specifically, supervised ML models include classification, regression models, etc. Unsupervised ML models include, for example, clustering models. Deep-learning algorithms are a part of ML algorithms based on artificial neural networks with representation learning. For example, the deep-learning algorithm may run data through multiple layers of neural network algorithms, each of which passes a simplified representation of the data to the next layer. With respect to neural networks, for example, a neural network may include one or more hidden layers, where a hidden layer includes one or more neurons. A neuron may be a modelling node or object that is loosely patterned on a neuron of the human brain. In particular, a neuron may combine data inputs with a set of coefficients, i.e., a set of network weights and biases for adjusting the data inputs. These network weights and biases may amplify or reduce the value of a particular data input, thereby assigning an amount of significance to various data inputs for a task being modeled. Through machine learning, a neural network may determine which data inputs should receive greater priority in determining one or more specified outputs of the neural network. Likewise, these weighted data inputs may be summed such that this sum is communicated through an activation function of a neuron to other hidden layers within the neural network. As such, the activation function may determine whether, and to what extent, an output of a neuron progresses to other neurons where the output may be weighted again for use as an input to the next hidden layer.
In some embodiments, a machine-learning model may include an encoder model that transforms input data to a latent representation vector. The machine-learning model may further amalgamate the latent representation vector with a vector representation of a particular parameterization to produced combined data, e.g., using in a latent space domain. Likewise, the machine-learning model may also include a decoder model that transforms the combined vector into the corresponding output data according to the parameterization.
In some embodiments, the machine-learning model is a variational autoencoder. For example, variational autoencoders may compress input information into a constrained multivariate latent distribution through encoding in order to reconstruct the information during a decoding process. Thus, variational autoencoders may be used in unsupervised, semi-supervised, and/or supervised machine-learning algorithms. More specifically, variational autoencoders may perform a dimensionality reduction that reduces the number of features within an input dataset (such as an input gather). This dimensionality reduction may be performed by selection (e.g., only some existing features are preserved) or by extraction (e.g., a reduced number of new features are produced from preexisting features). Thus, an encoder process may compress the input data (i.e., from an initial space to an encoded space or latent space), while a decoder process may decompress the compressed data. This compression may be lossy, such that a portion of the original information in the input dataset cannot be recovered during the decoding process.
In some embodiments, various types of machine learning algorithms may be used to train the model, such as a backpropagation algorithm. In a backpropagation algorithm, gradients are computed for each hidden layer of a neural network in reverse from the layer closest to the output layer proceeding to the layer closest to the input layer. As such, a gradient may be calculated using the transpose of the weights of a respective hidden layer based on an error function (also called a “loss function.”) The error function may be based on various criteria, such as mean squared error function, a similarity function, etc., where the error function may be used as a feedback mechanism for tuning weights in the electronic model.
In some embodiments, a machine-learning model is trained using multiple epochs. For example, an epoch may be an iteration of a model through a portion or all of a training dataset. For example, the training data may include labeled images of interactions that are classified with one or more predetermined interactions. As such, a single machine-learning epoch may correspond to a specific batch of training data, where the training data is divided into multiple batches for multiple epochs. Thus, a machine-learning model may be trained iteratively using epochs until the model achieves a predetermined criterion, such as predetermined level of prediction accuracy or training over a specific number of machine-learning epochs or iterations. Thus, better training of a model may lead to better predictions by a trained model.
In accordance with one or more embodiments disclosed methods and systems may obtain training data that includes a plurality of labeled interactions of historical interactions. A respective labeled interaction among the plurality of labeled interactions may correspond to a predetermined interaction. The coreflooding simulation model may then be trained using the training data.
Turning to
The cell 331 of fluid cell 336 is defined in part by the cell inner wall 337 of a cell body 301. The top part of the test apparatus 300 comprises a core sample holder (e.g., a holder 338). The cell body 301 is a cylindrical tube with two opening ends. The top opening is connected to the core sample holder, and the bottom opening is closed by a first end cap 332 comprising a first cap body (e.g., a cap body 302) and a cap retainer nut 303. The first end cap set (e.g., the first end cap 332) may be held together by a snap ring (e.g., a snap ring 353.) When threading the cap retainer nut 303 onto the cell body, this connection allows the cap body 302 to move along the axial direction only, i.e., cap body 302 may move substantially parallel with a body axis (e.g., an axis 380).
The piston 392 located inside of the cell body is used to separate a pump-injected fluid from the testing fluid (e.g., a candidate injection fluid) that will flow through the core sample. The piston 392 has a lower end (e.g., a piston hydraulic side 374) that is exposed to a pump-injected fluid, such as a hydraulic fluid. The pump-injected fluid is provided by a pump fluid source. A hydraulic pressure pump pressurizes the hydraulic fluid from the hydraulic source to form the pump-injected fluid (e.g., a pressurized fluid). The pressurized fluid is pumped into the hydraulic chamber 334 using the hydraulic fitting 307. The piston 392 has an upper end (e.g., a piston treatment fluid side 371) that is exposed to the treatment fluid contained in cell 331. Piston 392 pressurizes the treatment fluid in cell 331 to convey the treatment fluid through a core sample (e.g., a core sample 341).
A piston sealing element (e.g., the piston o-ring 305) on the piston 392 and a first cap sealing element (e.g., a first cap o-ring 306) on the cap body 302 are used for sealing. The piston o-ring 305 forms a slidable seal between the piston 392 and the cell body 301. The first cap o-ring 306 forms a seal between the first end cap body (e.g., the cap body 302) and the cell body 301. A core piston (e.g., a movable plug 383) is configured to have a sliding fit inside the core sleeve (e.g., a core sleeve 311). A movable plug sealing element (e.g., a core piston o-ring 315) forms a slidable seal between the movable plug 383 and a sleeve inner surface 345 of the core sleeve 311. A tube fitting (e.g., a hydraulic fitting 307) can be used to connect a tubing (not shown) for pumping the pump-injected fluid, (e.g., the hydraulic substance) into the hydraulic chamber 334. In accordance with one or more embodiments the piston 392 may be a plunger and the sealing element, e.g., the piston o-ring 305, may be installed in a sleeve o-ring groove of the cell body 301.
The core sample 341 has a core outer surface 335, a core front surface (e.g., a core outlet end face 375), and a core back surface (e.g., a core inlet end face 376). The core sample 341 is loaded into the core sleeve 311, with a fixed plug 312 and the movable plug 383 inserted from the two ends of the sleeve. The fixed plug 312 is coupled to a sleeve first end 377 and the movable plug 383 is inserted into a sleeve second end 378. The fixed plug 312 has an end plug sample surface 379 that is arranged to form a core back surface-surface contact with the core back surface (e.g., the core inlet end face 376). The movable plug 383 has a core piston surface (e.g., an end plug surface 343) that is arranged to form a core front surface-surface contact with the core front surface (e.g., the core outlet end face 375). Thus, cell 331 of fluid cell 336 is enclosed by the cell inner wall 337, the fixed plug 312 of the holder 338, the core inlet end face 376, and the piston treatment fluid side 371. Likewise, the hydraulic chamber 334 of fluid cell 336 is enclosed by the cell inner wall 337, the cap body 302 of the first end cap 332, and the piston hydraulic side 374.
In accordance with one or more embodiments the core sleeve 311 is conformable to the shape of the core sample 341. For example, the conformable sleeve (e.g., the core sleeve 311) may comprise a flexible material such as rubber. The core sleeve 311 has a sleeve inner surface 345. The conformable sleeve may form a core outer surface-surface contact between the core outer surface 335 and the sleeve inner surface 345. Thus, this flexible type of sleeve (e.g., the core sleeve 311) can accommodate varied outside diameters and various outside diameter surface finishes of core samples.
As coupled to the cell body, the fixed plug 312 will be positioned near the top of the fluid cell body (e.g., the cell body 301). A bevel 342 disposed on the cell body 301 cooperates with a taper 351 on the fixed plug 312 to position fixed plug 312 with respect to cell body 301 along axis 380. Various o-rings are used for sealing. A protrusion sealing element (e.g., a protrusion o-ring 316) forms a seal between an end plug protrusion outer surface and the sleeve inner surface 345. A lip sealing element (e.g., a lip o-ring 317) forms a seal between a lip of the core holder body and an end plug seal surface. A taper sealing element (e.g., a taper o-ring 318) forms a seal between the taper 351 and the bevel 342.
A translatable tube is translatable through the second end cap 339 while maintaining a seal between the tube OD and the second end cap 339. In this sense the translatable tube may be known as a movable tube (e.g., a tubing 319) with a sealing fit between the translatable tube and the second end cap. The tubing 319 is connected to the core movable plug (e.g., movable plug 383) by a movable tubing fitting 320. The commonly used tubing fittings are ferrules and glands or nuts. The movable plug 383 may translate along, or parallel to, the axis 380, i.e., the movable plug 383 may move with respect to the core sleeve 311 along the axis 380. The movable feature of the movable plug 383 enables a longitudinal flexibility along axis 380 of the holder 338 for various sizes of core samples. Thus, this flexible type of end plug (e.g., the movable plug 383) can accommodate varied lengths of core samples.
In accordance with one or more embodiments, a small hole (e.g., a movable tubing hole 349) is disposed on the end cap body (e.g., the second cap body 309). The movable tube may slide in and out of the second cap body 309 while simultaneously sealing using a seal between the tube and the cap. The small hole allows the tubing 319 to go through the hole and to allow axial movement of the tubing. The diameter of the small hole on the cap body is slightly larger than the outside diameter of the tubing 319 to enable the tubing 319 to move along the axis 380 with respect to the end cap body. The small gap between the hole and tubing 319 is sealed by a cap-to-tube sealing element such as an o-ring to form a linear motion seal between the movable tubing hole 349 and the tubing 319. For example, the small gap may be sealed by compressing the cap-to-tube scaling element (e.g., a cap tube o-ring 321) using a gland nut 322.
After the core holder part (e.g., the holder 338) is connected with the fluid cell (e.g., the fluid cell 336) by threading the core holder body (e.g., core holder body 308) onto the cell body (e.g., cell body 301), a heating jacket (e.g., jacket 323) may be put on the outside of the whole assembly for tests at high temperature, e.g., tests at temperatures higher than ambient temperature. Alternatively, a cooling jacket may be used for performing tests at temperatures lower than ambient temperature. Ports (e.g., a first confining port 324 and a second confining port 325) are used for applying a confining pressure to the core sample by pressurizing a confining chamber 333. The confining pressure may be developed by pressurizing a confining substance. An example confining substance is a confining fluid such as a hydraulic oil or water from a confining substance source using a confining pressure pump. The confining chamber is configured for confining pressure to be applied to the exterior of the core sleeve and to a movable plug front 344 surface. Confining pressure applied to the movable plug front 344 surface may move the piston along axis 380 toward the core sample 341. And example of a confining pressure is a high pressure such as a pressure higher than ambient pressure. An example of a high pressure is a pressure equivalent to a downhole environment or reservoir pressure.
The monitoring subsystem 455 may have a communication interface 442. The communication interface may be coupled to the monitoring subsystem. The communication interface may also be coupled to a processor such as the controller processor 413 and to a memory 408. The communication interface is configured to transmit the coreflooding simulation data to a control system such as the controller 426. The memory is configured to store the coreflooding simulation data. The memory may also be coupled to the processor. The memory may have instructions for performing a method such as obtaining a command to generate the coreflooding simulation data, generating the coreflooding simulation data, and transmitting the coreflooding simulation data using the communication interface.
The test fluid flowing out of tubing 419 is received by a test fluid receiving tank 470. A first confining port (e.g., the first confining port 324,
The testing fluids are pressurized using the hydraulic pump by pressurizing a pump-injected fluid (e.g., a hydraulic fluid 473) on a piston hydraulic side (e.g., piston hydraulic side 474). The pump-injected fluid is provided by a hydraulic fluid source (e.g., hydraulic source 472). The hydraulic fluid is introduced into a hydraulic chamber 434 from the hydraulic source. A hydraulic pump (e.g., a first pump 432) pressurizes the hydraulic fluid to form the pressurized fluid. The first pump 432 may be part of a first pump system that includes various pump accessories such as power switch, pressure regulator, pressure relief valve, pressure bypass valve, recirculation circuit, monitoring features (pressure gauge, fluid level gauge, etc.), and other controls. The pressure is conveyed into the hydraulic chamber 434 using a hydraulic fitting 407 such that the hydraulic chamber is under pressure from the pressurized fluid. In this manner the piston 404 pressurizes the test fluid in cell 431 against the core inlet end face. The piston displaces test fluid to deliver the test fluid into and through the core sample. The test fluid flows through the core sample, out of the sample at the core outlet end face, out of the apparatus out through tubing 419. The test fluid flowing out of tubing 419 is received by the test fluid receiving tank 470.
The test apparatus may include a heating jacket or heating blanket (e.g., a jacket 460) for temperature control with the heating jacket covering, for example, the core holder, the confining chamber 433, the hydraulic chamber 434, and the injection fluid. In accordance with one or more embodiments the jacket 460 may comprise a cooling jacket or cooling sleeve used for reducing the temperature of the apparatus to a temperature below room temperature. The jacket 460 may make contact with the components of the system or the jacket may be in proximity to the components. The monitoring subsystem may detect temperature from the jacket, between the jacket and the components, or within the components. The monitoring subsystem may detect a current draw (e.g., an amperage) of electricity being drawn by the jacket. The monitoring subsystem may detect a flowrate and temperature of a heating medium or cooling medium being circulated through the jacket.
Turning to
In accordance with one or more embodiments the injection fluid is a candidate injection fluid, i.e., a test fluid or core flood fluid. The candidate injection fluid may be a chemical blend or chemical formulation that the investigators have prepared and have nominated as a candidate to be tested with the core sample acquired from the reservoir of interest. The investigators may have nominated the test fluid based on historical data of interactions between historical fluids and historical reservoirs, i.e., injection fluids that have been used in the past with formations similar to the formation of interest.
Next is a cell joining step 506. The assembly of the core, the sleeve, and the core end plugs is then disposed on the top of the fluid cell (e.g., the cell body 301) with the fixed plug 312 positioned on the top rim (e.g., on the bevel 342) of the cell body 301. Then, the lip o-ring 317 is installed onto the bottom end of the core holder body 308, and the core holder body 308 is threaded onto the cell body 301 to push the fixed plug 312 along the axis 380 (e.g., downward) to contact the cell body rim at the bevel 342 and to compress the taper o-ring 318 between the bevel 342 and the taper 351.
Following these actions is a confining step 508 that includes the following steps. The tubing 319 is inserted through the small hole on the cap body (e.g., the second end cap body 9), then the second end cap 339 is put onto the top end of the core holder body 308 to close the confining chamber. The cap body will be pushed downward along axis 380 when threading the cap retainer 310 onto the core holder body 308. The second cap o-ring 314 on the cap body seals the gap, thereby forming a seal, between the cap body and the core holder body 308. After closing this end cap, the cap tube o-ring 321 is put over the tubing 319 and the gland nut 322 is used to seal the gap outside of tubing 319. A heating jacket is put on the outside of the whole assembly (the test apparatus 300) for high-temperature tests.
A general sequence for readying the test apparatus 300 for performing a test are as follows (e.g., a confine core step 510). The air from the confining chamber is bled out. The confining substance is pumped from the confining substance source through the first confining port 324 to fill the void space (e.g., the confining chamber 333) inside of the core holder body, and the air can be pushed out (i.e., the air can be bled out) through the second confining port 325. After fully filling the void space, the second confining port 325 is closed and a target confining pressure is applied to the core samples. Hydrostatic confining pressure in the confining chamber applies the axial pressure and the radial pressure to the core thereby conforming, using the confining pressure, the conformable sleeve around the core sample to form the core outer surface-surface contact between the sleeve inner surface and the core outer surface.
A translate tube step 512 follows. The translatable type of end cap (e.g., a core end plug or core piston, i.e., the movable plug 383) translated by the confining pressure allows the end plug surface 343 to form a core end surface-surface contact with the core outlet end face 375. As the movable plug 383 translates along axis 380, the tubing 319 moves slightly along axis 380 through cap tube o-ring 321 and gland nut 322. The translating of the movable plug 383 and the tubing 319 forms the core end surface-surface contact with the core outlet end face. The fixed plug 312 is coupled to the sleeve first end 377 of the core sleeve 311. The translating also translates the core sample 341 to contact the end plug sample surface 379 of the core end plug (e.g., the fixed plug 312) to form the core back surface-surface contact with the core back surface (e.g., the core inlet end face 376) of the core sample 341. In this manner, a sample confining pressure is applied onto the core sample in both a radial direction and an axial direction.
At step 610, the production method includes acquiring a core sample from a first reservoir of interest; wherein the first reservoir is producing hydrocarbons at a first recovery rate.
At step 620, the production method includes performing, by a core flood apparatus, a coreflooding study comprising a plurality of coreflooding simulations using the core sample disposed in the core flood apparatus. Each coreflooding simulation investigates an interaction between a core flood fluid and a core sample. The interaction may be affected by several test factors such as environmental parameters (e.g., pressure, temperature), core sample parameters (e.g., porosity), and core flood fluid parameters (e.g., chemical formulation or chemical blend, injection pressure.) The study detects the interaction and compares the interaction with a desired outcome, e.g., a predetermined criterion of a set of predetermined criteria. The desired outcome may be, for example, an interaction indicative of an improved recovery rate or flowrate. The indication may be that when an adjusted treatment fluid is injected into the reservoir, a second recovery rate results and the second recovery rate is greater than the first recovery rate or flowrate. The comparison result may be that the interaction satisfies the predetermined criteria (or a criterion of the criteria). The result may be that the interaction fails to satisfy the predetermined criterion. The outcome of the comparison may result in an action taken. For example, the control system may automatically determine whether the first coreflooding simulation satisfies a predetermined criterion. If the first coreflooding simulation fails to satisfy the predetermined criterion, then the control system may automatically determine replacement simulation parameters for the coreflooding simulation test.
The method may include obtaining first acquired coreflooding simulation data regarding one or more simulation parameters in real-time during a coreflooding simulation test of the plurality of coreflooding simulations for the core sample. The method may then use a control system to automatically determine a first coreflooding simulation using the first acquired coreflooding simulation data. The determining may be based on the coreflooding simulation model. The first coreflooding simulation may include a real-time simulation of coreflooding the first reservoir at a current set of flooding parameters in the coreflooding simulation test.
The method may then use the control system to automatically determine whether or not the first coreflooding simulation satisfies a predetermined criterion. The control system may determine a second coreflooding simulation based on using the replacement simulation parameters for the coreflooding simulation test. The determining may be based on the coreflooding simulation model. The method may include the control system automatically transmitting to the core flood apparatus a first command to update the coreflooding simulation test to implement the replacement simulation parameters.
At step 630, the production method includes performing, by a control system and using a coreflooding simulation model, a reservoir simulation study on the first reservoir using the coreflooding study. The outcome of the coreflooding simulation model may be a validated and optimized treatment fluid formula in core scale for a reservoir. The coreflooding simulation model results may then be used as a source of input parameters for numerical reservoir simulation studies. The coreflooding simulation model may be an artificial neural network comprising an input layer, a plurality of hidden layers, and an output layer.
The core sample in the core flood apparatus may be in a coreflooding system. The first acquired coreflooding simulation data may include introducing the current set of flooding parameters into the core flood apparatus. The first acquired coreflooding simulation data may be an interaction within the core flood apparatus between the current set of flooding parameters and the core sample, and the method may include detecting the interaction. The predetermined criterion may correspond to a predetermined interaction.
The coreflooding study may correspond to a first set of flooding parameters that has a first core flood fluid tested using the first set of flooding parameters. The replacement simulation parameters may have a second set of flooding parameters that has the adjusted treatment fluid. The second coreflooding simulation may correspond to the adjusted treatment fluid tested using the second set of flooding parameters.
The method may include obtaining historical reservoir data for one or more wells at a predetermined distance from the first reservoir. The coreflooding simulation model may use the historical reservoir data to determine the predetermined criterion. The method may include obtaining training data that has a plurality of labeled interactions of historical interactions. A respective labeled interaction among the plurality of labeled interactions may correspond to the predetermined interaction. The method may include performing a training operation of the coreflooding simulation model using the training data.
The computer processor may determine, based on the coreflooding simulation model, a third coreflooding simulation based on using the replacement simulation parameters for the coreflooding simulation test. The replacement simulation parameters may have a third set of flooding parameters that has a third core flood fluid. The third coreflooding simulation may corresponds to the third core flood fluid tested using the third set of flooding parameters. The control system may automatically transmit to the core flood apparatus a second command to terminate the coreflooding simulation test in response to determining that the third coreflooding simulation fails to satisfy the predetermined criterion.
At step 640, the production method includes automatically adjusting, by the control system, a core flood fluid based on the reservoir simulation study to form an adjusted treatment fluid that produces a second recovery rate from the first reservoir. The second recovery rate may be greater than the first recovery rate. For example, the chemical formula of the candidate injection fluid may be adjusted to form a replacement candidate formulation of a candidate injection fluid. The candidate injection fluid may be tested one or more times. Various other simulation parameters such as the candidate viscosity, concentration, flowrate, and pressure may be adjusted to form replacement simulation parameters. The method may include using the control system, the coreflooding simulation model, and the predetermined interaction to automatically determine the second recovery rate.
At step 650, the production method includes performing, using an injection well, an injection operation of a reservoir using the adjusted treatment fluid. For example, after the results from the numerical reservoir simulation studies are obtained, then the optimized injection strategies may be applied to a chemical flooding operation such as waterflooding, EOR, and formation damage evaluations. The method may include producing the hydrocarbons at the second recovery rate from a production well coupled to the first reservoir. The control system may have further functionality for performing the steps of the method. For example, the control system may perform the coreflooding study using the core flood apparatus with a core sample in the core flood apparatus. The control system may have functionality for performing a reservoir simulation study on the first reservoir using the coreflooding study and a coreflooding simulation model. The control system may have functionality for adjusting a core flood fluid based on the reservoir simulation study to form an adjusted treatment fluid that produces a second recovery rate from the first reservoir. The control system may have functionality for performing an injection operation of a reservoir using an injection well and the adjusted treatment fluid.
Embodiments may be implemented on a computer system.
The computer 702 can serve in a role as a client, network component, a server, a database or other persistency, or any other component (or a combination of roles) of a computer system for performing the subject matter described in the instant disclosure. The illustrated computer (computer 702) is communicably coupled with a network 716. In some implementations, one or more components of the computer 702 may be configured to operate within environments, including cloud-computing-based, local, global, or other environment (or a combination of environments).
At a high level, the computer 702 is an electronic computing device operable to receive, transmit, process, store, or manage data and information associated with the described subject matter. According to some implementations, the computer 702 may also include or be communicably coupled with an application server, e-mail server, web server, caching server, streaming data server, business intelligence server, or other server (or a combination of servers).
The computer 702 can receive requests over network 716 from a client application (for example, executing on another computer 702) and responding to the received requests by processing the said requests in an appropriate software application. In addition, requests may also be sent to the computer 702 from internal users (for example, from a command console or by other appropriate access method), external or third-parties, other automated applications, as well as any other appropriate entities, individuals, systems, or computers.
Each of the components of the computer 702 can communicate using a system bus 704. In some implementations, any or all of the components of the computer 702, both hardware or software (or a combination of hardware and software), may interface with each other or the interface 706 (or a combination of both) over the system bus 704 using an application programming interface (an API 712) or a service layer 714 (or a combination of the API 712 and service layer 714. The API 712 may include specifications for routines, data structures, and object classes. The API 712 may be either computer-language independent or dependent and refer to a complete interface, a single function, or even a set of APIs. The service layer 714 provides software services to the computer 702 or other components (whether or not illustrated) that are communicably coupled to the computer 702. The functionality of the computer 702 may be accessible for all service consumers using this service layer. Software services, such as those provided by the service layer 714, provide reusable, defined business functionalities through a defined interface. For example, the interface may be software written in JAVA, C++, or other suitable language providing data in extensible markup language (XML) format or other suitable format. While illustrated as an integrated component of the computer 702, alternative implementations may illustrate the API 712 or the service layer 714 as stand-alone components in relation to other components of the computer 702 or other components (whether or not illustrated) that are communicably coupled to the computer 702. Moreover, any or all parts of the API 712 or the service layer 714 may be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.
The computer 702 includes an interface 706. Although illustrated as a single interface in
The computer 702 includes at least one of a computer processor 718. Although illustrated as a single computer processor in
The computer 702 also includes a memory 708 that holds data for the computer 702 or other components (or a combination of both) that can be connected to the network 716. For example, memory 708 can be a database storing data consistent with this disclosure. Although illustrated as a single memory in
The application 710 is an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer 702, particularly with respect to functionality described in this disclosure. For example, application 710 can serve as one or more components, modules, applications, etc. Further, although illustrated as a single one of application 710, the application 710 may be implemented as a multiple quantity of application 710 on the computer 702. In addition, although illustrated as integral to the computer 702, in alternative implementations, the application 710 can be external to the computer 702.
There may be any number of computers such as the computer 702 associated with, or external to, a computer system containing computer 702, each computer 702 communicating over network 716. Further, the term “client,” “user,” and other appropriate terminology may be used interchangeably as appropriate without departing from the scope of this disclosure. Moreover, this disclosure contemplates that many users may use one of computer 702, or that one user may use multiple computers such as computer 702.
In some embodiments, the computer 702 is implemented as part of a cloud computing system. For example, a cloud computing system may include one or more remote servers along with various other cloud components, such as cloud storage units and edge servers. In particular, a cloud computing system may perform one or more computing operations without direct active management by a user device or local computer system. As such, a cloud computing system may have different functions distributed over multiple locations from a central server, which may be performed using one or more Internet connections. More specifically, a cloud computing system may operate according to one or more service models, such as infrastructure as a service (IaaS), platform as a service (PaaS), software as a service (SaaS), mobile “backend” as a service (MBaaS), serverless computing, artificial intelligence (AI) as a service (AIaaS), and/or function as a service (FaaS).
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.
| Number | Name | Date | Kind |
|---|---|---|---|
| 4599891 | Brauer et al. | Jul 1986 | A |
| 4753107 | Reed et al. | Jun 1988 | A |
| 8356510 | Coenen | Jan 2013 | B2 |
| 20120310614 | Beattie | Dec 2012 | A1 |
| 20130248176 | Sunde | Sep 2013 | A1 |
| 20150268314 | Peterson | Sep 2015 | A1 |
| 20160025895 | Ziauddin | Jan 2016 | A1 |
| 20180149004 | Rao | May 2018 | A1 |
| 20180335374 | Kanj et al. | Nov 2018 | A1 |
| 20200110192 | Al Hashim | Apr 2020 | A1 |
| 20200271563 | Chen et al. | Aug 2020 | A1 |
| 20210302280 | Al-Qasim | Sep 2021 | A1 |
| 20220091091 | Hakimuddin | Mar 2022 | A1 |
| 20220154563 | AlYousif | May 2022 | A1 |
| 20220290540 | Al Shalabi | Sep 2022 | A1 |
| 20220307356 | Hou | Sep 2022 | A1 |
| 20230212943 | Wang | Jul 2023 | A1 |
| 20240141766 | Hou | May 2024 | A1 |
| 20240201064 | Wang | Jun 2024 | A1 |
