Patent Application
20240309748
Various oil and gas wells use tubular elements as components of the wellbore. However, tubular elements may be subject to corrosion and/or erosion over time. For example, the wellbore may be exposed to water, oil, and/or gas behind the tubular element (such as gas behind the casing) that may cause various chemical reactions with pipe components. These different chemical reactions may impact the casing and thus well integrity over time. Likewise, it may prove difficult to adjust production parameters to account for changes in tubular element conditions without accurate knowledge of casing conditions at various depth intervals and/or well sections.
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.
In general, in one aspect, embodiments relate to a system that includes a control system disposed on a well surface, a pipe component disposed in a wellbore, and a first corrosion recorder coupled to the pipe component. The first corrosion recorder includes a first magnetic field transmitter and a first magnetic field receiver. The first magnetic field transmitter and the first magnetic field receiver generate first corrosion sensor data. The first corrosion recorder also includes a first communication interface. The system also includes a second corrosion recorder coupled to the pipe component. The second corrosion recorder includes a second magnetic field transmitter and a second magnetic field receiver. The second magnetic field transmitter and the second magnetic field receiver generate second corrosion sensor data. The second corrosion recorder also includes a second communication interface. The system also includes an optical fiber cable disposed in the wellbore and coupled to the control system, the first corrosion recorder, and the second corrosion recorder. The first corrosion recorder transmits the first corrosion sensor data to the control system using the first communication interface. The second corrosion recorder transmits the second corrosion sensor data to the control system using the second communication interface. The first corrosion recorder and the second corrosion recorder are separated by a predetermined distance within the wellbore.
In general, in one aspect, embodiments relate to an apparatus that includes a magnetic field transmitter, a magnetic field receiver, a sealed case, a fiber optic connector configured to couple to an optical fiber cable, a communication interface coupled to the fiber optic connector, a processor coupled to the magnetic field transmitter, the magnetic field receiver, and the communication interface, and a memory coupled to the processor. The memory includes instructions to perform a method. The method steps include to obtain a command to generate corrosion sensor data, generate the corrosion sensor data using the magnetic field receiver and the magnetic field transmitter, and transmit the corrosion sensor data over the optical fiber cable using the communication interface.
In general, in one aspect, embodiments relate to a method that includes transmitting. by a control system, a first command to a first corrosion recorder in a wellbore. The method includes transmitting, by the control system, a second command to a second corrosion recorder in the wellbore. The first corrosion recorder and the second corrosion recorder are separated by a predetermined distance within the wellbore. The method includes obtaining, by the control system in response to transmitting the first command, first corrosion sensor data from the first corrosion recorder. The method includes obtaining, by the control system in response to transmitting the second command, second corrosion sensor data from the second corrosion recorder. The first corrosion sensor data and the second corrosion sensor data are generated using various magnetic field receivers and various magnetic field transmitters. The first corrosion sensor data describes a first portion of a pipe component disposed in the wellbore. The second corrosion sensor data describes a second portion of the pipe component that is different from the first portion.
In light of the structure and functions described above, embodiments of the invention 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.
In general, embodiments of the disclosure include systems and methods for monitoring one or more pipe sections of a wellbore for corrosion. In particular, monitoring corrosion may prove difficult in a wellbore, especially throughout the life of a wellbore. Past techniques to analyze corrosion uses various wireline methods that lowered monitoring equipment into a well with running tools to measure corrosion. Rather than using well running operations, some embodiments provide a permanent system for recording and collecting corrosion sensor data continuously for various pipe components. Examples of pipe components may include various tubulars, such as casing pipes and tubing pipes. Moreover, various corrosion recorders may be disposed at different depth intervals to analyze different sections of pipe. Using a communication cable (e.g., an optical fiber cable), the corrosion records may communicate corrosion sensor data with well surface equipment, such as a control system. In some embodiments, corrosion sensor data at different locations are combined to generate a corrosion log of a wellbore. In a corrosion log, corrosion measurements may be described as a function of depth in the wellbore. By collecting corrosion data over time, changes to the wellbore may be simulated and predicted, such as for maintenance operations and tubular replacement operations.
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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 (e.g., a computer (702)) described below in
The wellbore (120) may include a bored hole that extends from the surface (108) into a target zone of the hydrocarbon-bearing 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 hydrocarbon-bearing 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 production (“production”) (121) (e.g., oil and gas) from the reservoir (102) to the surface (108) during production operations, the injection of substances (e.g., water) into the hydrocarbon-bearing formation (104) or the reservoir (102) during injection operations, or the communication of monitoring devices (e.g., logging tools) into the hydrocarbon-bearing 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 (140) for the well system (106) and other data regarding downhole equipment and downhole sensors (e.g., using a corrosion sensing system described below in
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 (121) 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 (121). For example, a production valve (132) may be fully opened to enable unrestricted flow of production (121) from the wellbore (120), the production valve (132) may be partially opened to partially restrict (or “throttle”) the flow of production (121) from the wellbore (120), and production valve (132) may be fully closed to fully restrict (or “block”) the flow of production (121) from the wellbore (120), and through the well surface system (124).
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In some embodiments, the surface sensing system (134) includes a surface pressure sensor (136) operable to sense the pressure of production (121) 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 (121) 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 (121) 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 (121) 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 (139) operable to sense the flow rate of production (121) flowing through the well surface system (124), after it exits the wellbore (120). The flow rate sensor (139) may include hardware that senses a flow rate of production (121) (Q) passing through the wellhead (130).
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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 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
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In some embodiments, a corrosion log is generated from corrosion sensor data. A corrosion log may be a data record that is obtained using a corrosion sensing system. Likewise, corrosion sensor data may also be monitored at a well continuously in real-time. An example of a corrosion log is illustrated in
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In some embodiments, a corrosion recorder is positioned at one depth interval in a casing section above a packer and another corrosion recorder may be positioned at another depth interval below the packer. As such, corrosion recorders may be separated by predetermined distances for analyzing pipe components throughout a wellbore. The packer may be a feed-through style packer to accommodate a communication cable crossing from an up-hole side of the packer to a downhole side. The feed-through packer may include a feature, such as a gland and gland nut pair, that seals the communication cable to prevent pressure and flow communication along an accommodation path, such as a hole or a port, of the cable that feeds through the packer. Packers may isolate an annulus and anchor tubular elements in a wellbore. The packer may be based on wellbore geometry and operational characteristics of the wellbore fluids, such as completion and reservoir fluids. The packer may be a retrievable packer or a permanent packer. Furthermore, a communication cable may continue to another corrosion recorder located at the third depth interval below the second corrosion recorder.
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In Block 600, one or commands are transmitted one or more corrosion recorders in a wellbore in accordance with one or more embodiments. For example, an optical fiber cable may be coupled to a control system and corrosion recorders using the fiber optic connectors. The corrosion recorders may be coupled to the tubular element(s) with the mount fixture similar to the mount fixture described above in
In Block 610, corrosion sensor data are obtained from one or more corrosion recorders in response to one or more commands in accordance with one or more embodiments.
In particular, sensor data may include tubular element wall thickness correlated with a time and date stamp to create a history. Corrosion sensor data may be obtained from the corrosion recorder(s) in response to receipt of a transmitted command(s). The control system may transmit the command. The first corrosion sensor data and the second corrosion sensor data are generated using one or more magnetic field receivers and one or more magnetic field transmitters.
In Block 620, a pipe thickness data of one or more pipe components are determined in a wellbore based on corrosion sensor data in accordance with one or more embodiments.
In Block 630, one or more well simulations of a wellbore are performed based on corrosion sensor data, pipe thickness data, and/or various pipe parameters in accordance with one or more embodiments. For example, a control system or a simulator device may use sensor data from a corrosion sensing system to solve various well equations in a particular simulation. In particular, corrosion sensor data may be used with wellhead data, geological data, and other types of data to predict the state of a wellbore and future well operations. Moreover, well simulations may include history matching such as matching the magnitude of corrosion over time, predicting a date or a range of dates for a pipe replacement operation, production rates at one or more wells and correlating the production rate with a corrosion rate, and determining the presence of gas behind the casing, monitoring gas behind the casing to avoid casing leaks. A well simulation may be performed for the purpose of determining a future date for a pipe replacement operation.
In Block 640, one or more well parameters are adjusted for a production operation based on corrosion sensor data, pipe thickness data, and/or one or more well simulations in accordance with one or more embodiments. For example, a production operation at the wellbore may be terminated (e.g., shut in the well) if a predetermined section (e.g., a depth interval) fails to satisfy the predetermined criterion (e.g., wall thickness remaining). Other examples of adjusting production parameters may include one or more of adjusting the production rate, adjusting the corrosion inhibitor injection rate, adjusting the corrosion inhibitor injection schedule, adjusting the corrosion inhibitor chemistry and/or concentration, or reducing the pressure of gas behind the casing.
In Block 650, a pipe replacement operation is performed based on corrosion sensor data, pipe thickness data, and/or one or more well simulations in accordance with one or more embodiments.
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 (730). 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 (730) 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 (703). 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 (704) (or a combination of both) over the system bus (703) using an application programming interface (an API (712)) or a service layer (713) (or a combination of the API (712) and service layer (713). 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 (713) 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 (713), 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 (713) 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 (713) 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 (704). Although illustrated as a single one of interface (704) in
The computer (702) includes at least one of a computer processor (705). Although illustrated as a single one of the computer processor (705) in
The computer (702) also includes a memory (706) that holds data for the computer (702) or other components (or a combination of both) that can be connected to the network (730). For example, memory (706) can be a database storing data consistent with this disclosure. Although illustrated as a single one of memory (706) in
The application (707) 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 (707) can serve as one or more components, modules, applications, etc. Further, although illustrated as a single one of application (707), the application (707) may be implemented as a multiple quantity of application (707) on the computer (702). In addition, although illustrated as integral to the computer (702), in alternative implementations, the application (707) 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 (730). 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 (AlaaS), 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.
