Patent Application
20250092781
Wellbores may be drilled into a surface location or seabed for a variety of exploratory or extraction purposes. For example, a wellbore may be drilled to access fluids, such as liquid and gaseous hydrocarbons, stored in subterranean formations and to extract the fluids from the formations. Wellbores used to produce or extract fluids may be formed in earthen formations using earth-boring tools such as drill bits for drilling wellbores and reamers for enlarging the diameters of wellbores.
In some cases, one or more sidetrack wellbores may be drilled from an existing wellbore. Sidetrack wellbores may be drilled to create a new wellbore path from the existing wellbore to access different zones or bypass obstructions while maintaining zonal isolation and well integrity. In order to plan and execute sidetrack drilling, one or more sidetrack windows or sidetrack zones in the wellbore are typically identified. The sidetrack zones may represent locations or depths within the wellbore with optimal or desirable conditions for drilling a sidetrack wellbore. Sidetrack zones are typically identified by a drilling engineer or other skilled operator manually analyzing drilling data in order to construct and evaluate plots of the wellbore to identify suitable zones for drilling the sidetrack wells. In many cases, this operator-dependent process is time-consuming, burdensome, and prone to human error. Thus, systems and methods for leveraging advanced algorithms and data-driven analytics in order to identify sidetrack zones in underground wellbores with efficiency and precision may be advantageous.
In some embodiments, a method of identifying sidetrack zones in an underground wellbore includes receiving hole-casing data, and determining one or more candidate sidetrack zones based on identifying cement overlap areas from the hole-casing data. The method further includes receiving completion data for one or more completion elements and determining a completion depth for each of the one or more completion elements based on the completion data. The method further includes selecting one or more sidetrack zones by filtering the one or more candidate sidetrack zones based on one or more of the completion depths. In some embodiments, the method is performed by a system. In some embodiments, the method is implemented as instructions stored on a computer-readable storage medium.
This summary is provided to introduce a selection of concepts that are further described 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. Additional features and aspects of embodiments of the disclosure will be set forth herein, and in part will be obvious from the description, or may be learned by the practice of such embodiments.
In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:
This disclosure generally relates to systems, methods, and computer readable storage media for identifying sidetrack zones in underground wellbores. A sidetrack identification system may be implemented on one or more computing devices in connection with a downhole system. The sidetrack identification system may receive data of various types for a wellbore of the downhole system. For example, the sidetrack identification system may receive hole-casing data, completion data, cementing data, and target data. Based on the hole-casing data, the sidetrack identification system may determine one or more candidate sidetrack zones. For example, the sidetrack identification system may identify depths and/or ranges of depths for layers of cement associated with various stages of casing installed in the wellbore. Based on identifying areas of overlap of the cement layers, the sidetrack identification system may determine the candidate sidetrack zones in areas with a single layer of cement fixing the casing to the wellbore.
The sidetrack identification system may filter or adjust the candidate sidetrack zones based on one or more criteria. For example, based on the completion data, the sidetrack identification system may identify the location of a production packer and may filter out one or more of the candidate sidetrack zones that are located below the production packer. In another example, based on the cementing data, the sidetrack identification system may identify a cement quality of the layers of cement throughout the wellbore and may filter out one or more candidate sidetrack zones associated with cement that is not of a good quality. In another example, based on the hole-casing data, the sidetrack identification system may identify one or more areas of shallow casing and may adjust one or more candidate sidetrack zones in the shallow casing areas to a single point.
In this way, the sidetrack identification system may determine one or more sidetrack zones for the wellbore. The sidetrack identification system may determine sidetrack zones in this way for a plurality of wellbores in parallel. For example, the sidetrack identification system may determine sidetrack zones for up to 50 or 100 wellbores simultaneously. The sidetrack identification system may operate in this way to determine sidetrack zones for one or more wellbores in as little as 12 seconds.
In some embodiments, the sidetrack identification system facilitates determining one or more sidetrack trajectories. For example, the sidetrack identification system may determine one or more trajectories through one or more of the sidetrack zones for a sidetrack wellbore to access an underground target. For instance, based on a cost function, the sidetrack identification system may select a trajectory based on cost or ease of implementation, expected production, etc.
As will be discussed in further detail below, the present disclosure includes a number of practical applications having features described herein that provide benefits and/or solve problems associated with detecting and avoiding potential collisions of a subject wellbore with one or more offset wellbores. Some example benefits are discussed herein in connection with various features and functionalities provided by a sidetrack identification system implemented on one or more computing device. It will be appreciated that benefits explicitly discussed in connection with one or more embodiments described herein are provided by way of example and are not intended to be an exhaustive list of all possible benefits of the sidetrack identification system.
Conventional sidetrack wellbore planning relies on manual efforts for determining suitable locations for drilling sidetrack wells. For example, drilling engineers typically manually analyze wellbore data and construct and evaluate plots of the wellbore in order to identify sidetrack zones. Typically, a skilled and experienced drilling engineer can spend approximately 1-2 hours or more analyzing the design of an existing wellbore in order to identify potential sidetrack locations. In contrast, the evaluation of the wellbore in accordance with the sidetrack identification system described herein can return the sidetrack zones for a wellbore in as few as 12 seconds.
Additionally, a drilling engineer may typically be tasked with analyzing many wellbores, such as up to 50 or 100 wellbores. Thus, the 1-2 hours typically spent evaluating one wellbore can consume hundreds of man-hours when applied over the course of an entire portfolio of wellbores. The present techniques of the sidetrack identification system, in contrast, can perform the sidetrack zone detection workflow for any number of wellbores in parallel. Thus, whether evaluating one wellbore, or a portfolio of 100 wellbores, the sidetrack identification system may still return the sidetrack zones for all of the wellbores cumulatively in as little as 12 seconds.
Further, in addition to the significant efficiency gains over conventional techniques, the sidetrack identification system may also provide improved accuracy. For example, consuming wellbore data, generating plots, and performing computations and evaluations manually introduces the risk of human error, inconsistencies, inaccuracies, and fatigue. Indeed, when considered over the course of 100-200 man-hours for evaluating an entire portfolio of wellbores, the manual efforts of conventional techniques are prone to issues related to the human element, regardless of the skill, experience, and competence of the drilling engineer. In contrast, by implementing the present techniques as a computer-implemented system, and in some cases, a cloud computing-implemented system, the sidetrack identification system may leverage computing resources to rapidly consume and analyze wellbore data and determine the sidetrack zones with precision and accuracy above what manual efforts may achieve. Thus, the sidetrack identification system may determine sidetrack zones at an extremely accelerated pace and with enhanced precision and accuracy. In this way, the present techniques can deliver rapid and accurate results for a substantial number of wells, significantly streamlining the sidetrack wellbore planning process.
Additional details will now be provided regarding systems described herein in relation to illustrative figures portraying example implementations. For example,
The drill string 105 may include several joints of drill pipe 108 connected end-to-end through tool joints 109. The drill string 105 transmits drilling fluid through a central bore and transmits rotational power from the drill rig 103 to the BHA 106. In some embodiments, the drill string 105 further includes additional downhole drilling tools and/or components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface 111. The drilling fluid discharges through selected-size nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, and for lifting cuttings out of the wellbore 102 as it is being drilled.
The BHA 106 may include the bit 110, other downhole drilling tools, or other components. An example BHA 106 may include additional or other downhole drilling tools or components (e.g., coupled between the drill string 105 and the bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing.
In general, the downhole system 100 may include other downhole drilling tools, components, and accessories such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). Additional components included in the downhole system 100 may be considered a part of the drilling tool assembly 104, the drill string 105, or a part of the BHA 106, depending on their locations in the downhole system 100.
The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials. For instance, the bit 110 may be a drill bit suitable for drilling the earth formation 101. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit 110 may be used with a whipstock to mill into casing 107 lining the wellbore 102. The bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to the surface 111, or may be allowed to fall downhole. The bit 110 may include one or more cutting elements for degrading the earth formation 101.
The BHA 106 may further include a rotary steerable system (RSS). The RSS may include directional drilling tools that change a direction of the bit 110, and thereby the trajectory of the wellbore. At least a portion of the RSS may maintain a geostationary position relative to an absolute reference frame, such as gravity, magnetic north, and/or true north. Using measurements obtained with the geostationary position, the RSS may locate the bit 110, change the course of the bit 110, and direct the directional drilling tools on a projected trajectory. The RSS may steer the bit 110 in accordance with or based on a trajectory for the bit 110. For example, a trajectory may be determined for directing the bit 110 toward one or more subterranean targets such as an oil or gas reservoir.
The downhole system 100 may include one or more client devices 112 with a sidetrack identification system 120 implemented thereon (e.g., implemented on one, several, or across multiple client devices 112). The client devices 112 may be located at the drilling site of the downhole system, or may be located at any other location and otherwise associated with the downhole system 100. The sidetrack identification system 120 may facilitate determining or identifying one or more sidetrack windows or sidetrack zones for drilling sidetrack wellbores off of the wellbore 102. In some embodiments, the sidetrack identification system 120 facilitates determining and/or selecting one or more trajectories for accessing a downhole target through one or more of the identified sidetrack zones.
The casing 107 may be fixed in place by cementing the casing with a cement 150. For example, after drilling a portion of the wellbore 102, one or more sections of the casing 107 may be positioned within the wellbore 102, and the cement 150 may be pumped down through the casing 107 and up through the annular space surrounding the outer diameter of the casing 107. In this way, the casing 107 may be cemented directly to the open wellbore, to a previously installed (e.g., outer) casing, or a combination of both. The casing 107 may be fixed in place in this manner to provide structural support to prevent the collapse of the wellbore wall. Additionally, the casing 107 may maintain wellbore integrity by isolating different geological formations, and/or may act as a conduit for fluids such as drilling mud and production fluids.
In some embodiments, the casing 107 includes a conductor casing 152. The conductor casing 152 may be an outermost casing string. The conductor casing 152 may be cemented to the wellbore 102, as shown, and may extend from the surface 111 down to a relatively shallow depth. The conductor casing 152 may be installed at the very beginning of the drilling process and may provide structural support and stability to the wellbore during drilling.
In some embodiments, the casing 107 includes a surface casing 154. The surface casing 154 may be positioned at least partly inside of, and may extend from, the conductor casing 152. The surface casing may be installed after the initial drilling of the shallow sections of the wellbore 102 to protect the relatively shallow formations from the drilling, operation, and/or production of the wellbore 102. For example, the surface casing 154 may be cemented in place and may create a secure barrier between the wellbore 102 and the surrounding formations to protect shallow aquifers and prevent contamination of groundwater. The surface casing 154 may also provide stability to the upper portions of the wellbore 102. As shown, the surface casing 154 may be cemented to the open wellbore 102 at one or more locations, and may also be cemented (e.g., at an upper portion) to the conductor casing 152. In this way, at least some of an overlapping portion of the conductor casing 152 and the surface casing 154 may exhibit several (e.g., 2) layers of cement 150 from an installation of each respective stage of casing 107.
In some embodiments, the casing 107 includes an intermediate casing 156. The intermediate casing 156 may be a stage of the casing 107 that is below the surface casing 154 but above a production zone 162. The intermediate casing 156 may be positioned at least partly inside of, and may extend from, the surface casing 154. The intermediate casing 156 may provide support for formations that may have high pressures, unstable rock structures, or other challenging conditions. The intermediate casing 156 may be cemented to create a seal and to isolate different geological zones to prevent fluid migration. Similar to the surface casing 154, the intermediate casing 156 may be cemented to the open wellbore 102 at one or more locations, and may also be cemented (e.g., at an upper portion) to the surface casing 154. Thus, in some embodiments, an overlapping portion of the intermediate casing 156 with the surface casing 154 exhibits several layers of cement 150 from an installation of each respective stage of casing 107.
In some embodiments, the casing 107 includes a production casing 158. The production casing 158 may be an innermost stage of the casing 107 and may be installed to reach the target or the production zone 162. The production casing 158 may be configured to withstand the high pressures and temperatures associated with the production of hydrocarbons or other resources from the production zone 162. The production casing 158 may also facilitate maintaining the integrity of the wellbore 102 during the extraction phase of the downhole system 100. Similar to the surface casing 154 and the intermediate casing 156, the production casing 158 may be cemented to the open wellbore 102 in the production zone 162 at one or more locations, and may also be cemented (e.g., at an upper portion) to the intermediate casing 156. Thus, in some embodiments, an overlapping portion of the production casing 158 with the intermediate casing 156 exhibits several layers of cement 150 from an installation of each respective stage of casing 107.
As mentioned, each of the stages of the casing 107 may extend at least partially into a previous stage of the casing 107. In some embodiments, one or more stages extend all the way to the surface 111. For example, one or more of the production casing 158, the intermediate casing 156, and the surface casing 154 may extend (e.g., through the previous stage) to the surface 111. In some embodiments, one or more stages of the casing 107 do not extend fully to the surface 111, such as a casing liner. For example, hangers, slips, seals, packers, etc. of a casing hanger assembly 164 may be positioned near the bottom of a previous stage of the casing 107, and the subsequent stage may be connected and/or sealed to the previous stage by the hanger assembly 164. The casing liner may be cemented to the wellbore 102 as described herein. In this way one or more stages of the casing 107 may be implemented as a casing liner and may be hung from a previous stage of the casing 107. In some embodiments, one or more components of the hanger assembly 164 are otherwise implemented to support, connect, secure, center, etc. the stages of casing 107 that do extend fully to the surface 111.
In some embodiments, one or more locations of the wellbore 102 exhibit multiple layers of cement due to multiple, successive stages of the casing 107. For example, an entirety of the annular space surrounding the outer diameter of a stage of casing 107 may be cemented to the wellbore 102 and/or to the previous, outer stage of casing 107. For instance, the surface casing 154 is shown cemented to the wellbore 102 at a lower portion and cemented to the conductor casing 152 at an upper section. In another example, a stage of casing 107 may be cemented up until the stage overlaps the previous stage of casing 107. For instance, the production casing 158 and the intermediate casing 156 are shown cemented to the wellbore 102, with little or no cement 150 in the annular space between successive stages of the casing 107. In some embodiments, a portion of the overlapping area between stages is cemented such that some of one stage is cemented to a previous stage of the casing 107. In this way, one or more locations may exhibit multiple layers of cement 150 at a same depth of the wellbore 102.
In some embodiments, a production tubing 160 is implemented in the wellbore 102. The production tubing 160 may facilitate the extraction of hydrocarbons from underground reservoirs. For example, the production tubing 160 may be a conduit through which hydrocarbons may flow from the production zone 162 to the surface 111 so they can be collected and processed. The production tubing 160 may be run into the wellbore 102 and may be secured in place and configured with various components such as hangars, packers, valves, joints, etc. In some embodiments, a production packer 166 is implemented in the wellbore 102. The production packer 166 may facilitate isolating the production zone 162 from one or more other geological zones or formations. For example, the production packer 166 may be positioned in and may seal the annular space between the intermediate casing 156 and the production tubing 160. In this way the production packer 166 may facilitate containing a reservoir pressure of the production zone 162 in order to control the flow of hydrocarbons through the production tubing 160.
The casing 107 may be implemented in the wellbore 102 in accordance with any of the techniques described herein, or any other techniques, and combinations thereof. Additionally, the example illustration of the wellbore 102 of
The client device 112 may refer to various types of computing devices. For example, one or more client devices 112 may include a mobile device such as a mobile telephone, a smartphone, a personal digital assistant (PDA), a tablet, a laptop, or any other portable device. Additionally, or alternatively, the client devices 112 may include one or more non-mobile devices such as a desktop computer, server device, surface or downhole processor or computer (e.g., associated with a sensor, system, function, etc. of the downhole system), or other non-portable devices. In one or more implementations, the client devices 112 include graphical user interfaces (GUIs) thereon (e.g., a screen of a mobile device). In addition, or as an alternative, one or more of the client devices 112 may be communicatively coupled (e.g., wired or wirelessly) to a display device having a graphical user interface thereon for providing a display of system content. The server device(s) 114 may similarly refer to various types of computing devices. Each of the devices of the environment 200 may include features and functionalities described below in connection with
As shown in
By way of example, one or more of the data receiving, gathering, and/or storing features of the data manager 122 may be delegated to other components of the sidetrack identification system 120. As another example, while candidate sidetrack zones may be determined and/or adjusted by the sidetrack zone engine 123, in some instances, some or all of these features may be performed by the filtering engine 124 (or other component of the sidetrack identification system 120). Indeed, it will be appreciated that some or all of the specific components may be combined into other components and specific functions may be performed by one or across multiple of the components 122-127 of the sidetrack identification system 120.
Additionally, while
As mentioned above, the sidetrack identification system 120 includes a data manager 122. The data manager 122 may receive and manage a variety of types of data of the sidetrack identification system 120, such as hole-casing data 132, completion data 134, and/or cementing data 136.
As just mentioned, the data manager 122 may receive hole-casing data 132. The hole-casing data 132 may include information related to one or more sections, stages, and/or components associated with the casing 107 installed in the wellbore 102. For example, as shown, the hole-casing data 132 may include information related to one or more stages of the casing 107, such as the conductor casing 152, surface casing 154, intermediate casing 156, and/or production casing 158 as described herein. The hole-casing data 132 may include information related to other components associated with the casing 107 and/or the wellbore 102 such as a tieback, or any other component. The hole-casing data 132 may identify an associated hole size (e.g., diameter), hole end measurement depth (MD), casing size, casing start MD, casing end MD, top MD of the cement of the associated component, drift inner diameter, and combinations thereof. The hole-casing data 132 may include any other information associated with the casing 107.
As mentioned, the data manager 122 may receive completion data 134. The completion data 134 may include information related to one or more completion components or completion elements associated with a completion of the wellbore 102. For example, as shown, the completion data 134 may include information related to various sections of tubing (e.g., production tubing 160), valves, packers, or any other completion element associated with the completion of the wellbore 102. The completion data 134 may identify a top MD, length, inner diameter, outer diameter, drift inner diameter, and combinations thereof. The completion data 134 may include any other information associated with the completion of the wellbore 102.
As mentioned, the data manager 122 may receive cementing data 136. The cementing data 136 may include information related to the cement 150 implemented to fix one or more components within the wellbore 102. For example, as shown, the cementing data 136 may identify a start and end depth, as well as a quality for one or more sections of the cement 150. In some embodiments, the cementing data 136 identifies an associated component for the section(s) of cement 150 identified in the cementing data 136. The cementing data 136 may include any other information associated with the cement 150.
In some embodiments, the data manager 122 receives target data 138. The target data may include information related to a subterranean target for the wellbore 102 and/or for one or more sidetrack wellbores. For example, the target data 138 may indicate a location, distance, boundary, orientation, size, and/or shape of an underground reservoir which the wellbore 102 and/or one or more sidetrack wellbores may potentially access. The target data 138 may identify a formation, substance, capacity, production zone, etc. for the reservoir. The target data 138 may include any other information associated with one or more underground targets.
In some embodiments, the data manager 122 receives user input. The data manager 122 may receive the user input, for example, via any of the client devices 112 and/or server devices 114. Any of the data described herein may be input or augmented via the user input. For example, in some instances, some or all of the sensor data is received by the data manager 122 as user input. In some instances, some or all of the hole-casing data 132, completion data 134, and/or cementing data 136 is received by the data manager 122 as user input. The user input may be received in association with one or more functions or features of the sidetrack identification system 120, such as part of determining and/or selecting a sidetrack window or trajectory. In this way, the data manager 122 may receive the user input to the sidetrack identification system 120.
In this way, the sidetrack identification system 120 may receive any of a variety of types of data. The data manager 122 may save and/or store any of the data it receives to the data storage 130. While the data manager 122 has been shown and described as receiving data associated with the wellbore 102, this reference to one singular wellbore is merely for illustrative purposes of the techniques described herein. In some embodiments, the data manager 122 receives data for many wellbores, such as up to 50 or 100 wellbores. Indeed, as described herein, the sidetrack identification system 120 may receive and utilize data from any number of wellbores in order to provide the sidetrack zone detection features and functionalities described herein for each wellbore in parallel and/or simultaneously.
In some embodiments, the data manager 122 cleans some or all of the data. For example, the data manager 122 may receive data in a variety of forms. The data manager 122 may profile the data to understand its structure, format, quality, etc. Based on the profiling, the data manager 122 may check for issues such as missing values, duplicate entries, outliers, inconsistent formats, etc. The data manager 122 may validate the data against one or more predefined rules and/or standards such as verifying that data is in an expected format or falls within an expected range. In some embodiments, the data manager 122 addresses any errors or inconsistencies. For example, the data manager 122 may remove incorrect, inconsistent, or duplicate entries. In another example, the data manager may correct incorrect, inconsistent, or missing entries, such as by estimating or averaging values based on an associated context. In another example, the data manager 122 may standardize the format or transform the format of the data for consistency. In another example, the data manager 122 may flag data issues for manual review and/or may facilitate a user correcting data issues. In this way, the data manager 122 may facilitate identifying and/or correcting errors, inconsistencies, or inaccuracies in the data to make the data more reliable and useful.
In some embodiments, the data manager 122 extracts and/or converts some or all of the data from various sources. For example, the data manager 122 may receive some or all of the hole-casing data 132, completion data 134, and/or target data 138 as reports, images, PDFs, or other documents and/or in one or more other formats. The data manager 122 may extract the data from these files, for example, through optical character recognition (OCR) or other extraction techniques. In some cases, the data manager 122 converts or exports the (e.g., extracted) data to a universal and/or industry standard format. For example, the data manager 122 may save the data to an open subsurface data universe (OSDU) format or standard. The data may be stored at a server in the OSDU format and may be recalled and/or accessed by the various components of the sidetrack identification system 120 in this format. The data manager 122 may store the data in any other format or according to any other standard. In some embodiments, the data manager 122 accesses the data in this format, for example, as extracted and/or converted by another system or user.
In some embodiments, the data manager 122 constructs a graph, plot, image, or other representation. For example, based on any of the data that it receives, the data manager 122 may generate a plot of some or all of the wellbore 102, such as that shown in
In some embodiments, the sidetrack zone engine 123 identifies candidate sidetrack zones as areas of the wellbore 102 exhibiting a single layer of cement 150. For example, the sidetrack zone engine 123 may access the hole-casing data 132 from the data storage 130. The sidetrack zone engine 123 may compare one or more of the MDs identified in the hole-casing data 132 associated with a specific component, section, or stage of the casing 107, and may determine one or more cement overlap areas 168 between the cement 150 associated with one component, and the cement 150 associated with another component. For instance, as shown in
As shown in
As mentioned above, the sidetrack identification system 120 includes a filtering engine 124. The filtering engine 124 may filter one or more of the candidate sidetrack zones 170, including further adjusting or modifying the candidate sidetrack zones 170.
In some embodiments, the filtering engine 124 filters and/or adjusts the candidate sidetrack zones 170 based on the cementing data 136. For example, as shown in
In some embodiments, poor cement quality is accompanied by various issues with the wellbore 102. For example, poor cement quality can lead to inadequate zonal isolation, risk of gas or fluid migration between geological zones or formations, casing corrosion or damage, loss of wellbore stability, reduced production efficiency, and safety and environmental risk, among other issues. Drilling sidetrack wellbores at or through these areas of poor cement quality may cause or exacerbate one or more of these issues. Accordingly, in some embodiments, the filtering engine 124 removes the “questionable” cement quality areas and/or the “bad” cement quality areas from the candidate sidetrack zones 170, as shown in
In some embodiments, the filtering engine 124 filters and/or adjusts the candidate sidetrack zones 170 based on the completion data 134. As discussed above, the completion data 134 may indicate the location of one or more completion elements associated with a completion of the wellbore 102, such as the production packer 166. In some cases, it may be dangerous, prohibited, or otherwise undesirable to drill sidetrack wells at, near, or below one or more of the completion elements. For example, as mentioned above, the production packer 166 may be a critical component that seals off and isolates the production zone from other parts of the wellbore 102. In some embodiments, drilling below the production packer can damage and/or compromise the integrity of the production packer leading to pressure loss and/or cross-contamination between geological zones or reservoirs. In other examples, drilling below the production packer 166 may risk introducing drilling fluids, cuttings, and other materials into the production zone which may contaminate the production zone (e.g., a reservoir), affect production quality, and/or pose safety risks. Further, drilling below the production packer may cause a loss of well control, which can lead to uncontrolled pressure releases, blowouts, or other emergency situations which may be highly dangerous and may result in significant safety risks and/or environmental damage. Additionally, in some cases, drilling below the production packer 166 is prohibited by local operational and/or environmental regulations. In some cases, drilling at, below, and/or through the production packer may be time-consuming and uneconomical.
In some embodiments, the filtering engine 124 identifies the location of the completion elements (e.g., production packer 166), as well as an associated threshold, limit or boundary associated with the completion elements. For example, as shown in
In some embodiments, the filtering engine 124 filters and/or adjusts the candidate sidetrack zones 170 based on the hole-casing data 132. For example, the filtering engine 124 may identify, from the hole-casing data 132, a type of one or more of the sections of casing 107 and an associated depth. Based on the type and/or depth, the filtering engine 124 may accordingly make an adjustment to the candidate sidetrack zones 170. For example, in some cases, drilling sidetrack wellbores in certain types of casings (e.g., conductor casings or surface casings), or in casings at or above a threshold depth (e.g., shallow casings) may be dangerous, may not be feasible, or may otherwise be inopportune or undesirable. For instance, shallow casings located near the surface of the wellbore 102 (e.g., within 1200 m) may have limited space for drilling tools, equipment, and/or wellbore geometry making it challenging to maneuver and operate drilling equipment effectively. In another example, shallow casing may be more prone to instability due to loose or unconsolidated formations near the surface which may increase the risk of wellbore collapse, damage to the casing, etc. Further, shallow formations may not provide adequate pressure containment, which may present well control issues such as blowouts. In another example, shallow drilling operations may risk contamination of groundwater and/or surface water, presenting significant environmental concerns. In some cases, shallow drilling may even be subject to additional environmental regulations and considerations.
In some embodiments, the filtering engine 124 identifies the location of one or more specific types of casing and/or one or more relevant threshold depths. For example, the filtering engine 124 may identify the surface casing 154 as a shallow casing. In another example, the filtering engine 124 may identify a threshold depth at about 1250 m. The filtering engine 124 may accordingly restrict or limit one or more candidate sidetrack zones 170 associated with the surface casing 154 and/or above the threshold depth. In some embodiments, the filtering engine 124 removes or reduces the candidate sidetrack zones 170 for the surface casing 154. In some embodiments, the filtering engine 124 removes or reduces the candidate sidetrack zones 170 at or above the threshold depth. In some embodiments, the filtering engine 124 does not remove a candidate sidetrack zone entirely, but reduces an applicable candidate sidetrack zone 170 to a single point or single depth. For example, as shown in
In this way, the filtering engine 124 may receive the candidate sidetrack zones 170 and may filter, adjust, or otherwise manipulate one or more of the candidate sidetrack zones 170 in order to identify one or more favorable areas to drill sidetrack wellbores based on a variety of criteria. The filtering engine 124 may store the candidate sidetrack zones 170 (at any of the various stages of filtering and/or adjusting) to the data storage 130 as sidetrack zones 140.
While the various filtering and adjusting functionalities of the filtering engine 124 have been described in succession, in stages, or otherwise in relation to each other, it should be understood that the filtering engine 124 may perform one or more (or all) of the functionalities described herein in combination, in isolation, in any order, or not at all. For example, while the filtering engine 124 has been described as filtering the candidate sidetrack zones 170 based on the production packer 166 after filtering based on the cementing data 136, it should be understood that the filtering based on the cementing data 136 may be performed after the filtering based on the production packer 166, or in some cases, not at all. Indeed, any of the functionalities of the filtering engine 124 and/or the sidetrack zone engine 123 for determining the candidate sidetrack zones 170, such as based on the cementing data 136, completion elements, shallow casings, cement overlap areas, etc., may be performed in any order and in any combination, including simultaneously or in parallel.
In this way, the sidetrack identification system 120 may determine one or more favorable sidetrack zones 140. In some embodiments, the sidetrack identification system 120 determines the sidetrack zones 140 quickly and efficiently. For example, the sidetrack identification system 120 implemented in accordance with the environment 200 described herein may facilitate determining the sidetrack zones 140 for the wellbore 102 in one minute or less, or even in as little as 12 seconds. In contrast, conventional, manual methods may be time-consuming and may take a drilling engineer up to 2 hours to complete. Thus, the efficiency provided by the computer and/or cloud computing nature of the sidetrack identification system 120 may provide significant benefits over conventional, manual methods.
In some embodiments, the sidetrack identification system 120 performs the features and functionalities described herein for a plurality of wellbores in parallel. For example, the sidetrack identification system 120 may receive data for up to 50 or 100 wellbores and may determine the sidetrack zones 140 for each of the wellbores simultaneously. The sidetrack identification system 120 may additionally receive target data for multiple targets for each wellbore and may determine the sidetrack zones 140 (and/or the trajectories as discussed below) for multiple targets for each wellbore. The sidetrack identification system may operate in parallel in this way in the same efficient manner, completing the workflow in as little as 12 seconds for all of the wellbores cumulatively. In this way, the efficiency advantages may be realized to an even greater degree when considering that the sidetrack identification system 120 can achieve, in a matter of seconds, what may take a drilling engineer up to 200 hours or more to achieve for 100 or more wellbores according to conventional techniques.
Further, the sidetrack identification system 120 may provide accuracy advantages. For example, manual analysis and computation, regardless of the skill and knowledge of the operator, introduces the risk of mistakes, inconsistency, human error, fatigue, and other inaccuracies. The sidetrack identification system 120, however, may perform the features and functionalities described herein independently, automatically, and without user input. Thus, the accuracy and consistency of the computer-implemented sidetrack identification system 120 may offer valuable accuracy benefits in addition to efficiency.
As mentioned above, the sidetrack identification system 120 includes a trajectory manager 125. The trajectory manager 125 may facilitate selecting a sidetrack zone 140, for example, for implementing a sidetrack trajectory for reaching or accessing a downhole target.
In some embodiments, the trajectory manager 125 generates one or more candidate trajectories 180. For example, the trajectory manager 125 may access the target data 138 and may identify one or more underground targets for accessing via one or more potential sidetrack wellbores. For example, an underground target may be a reservoir containing resources such as oil, gas, water, geothermal energy, or any other resource. An underground target may be a specific location or entry point of a reservoir, for example, to access a specific portion or store in a reservoir. The trajectory manager 125 may access the target data 138 for locating the underground target, and may access wellbore geometry data for identifying candidate trajectories 180 for reaching or accessing the target(s) through the identified sidetrack zones 140.
In some embodiments, the trajectory manager 125 identifies one or more candidate trajectories 180 for a given wellbore. In some embodiments, the trajectory manager 125 identifies one or more candidate trajectories 180 for many wellbores of an oilfield, basin, or other catalogue of (e.g., existing) wellbores. In some embodiments, the trajectory manager 125 determines all possible candidate trajectories 180 for accessing one, or multiple downhole targets.
As mentioned, the sidetrack identification system 120 includes a sidetrack risk engine 126. The sidetrack risk engine 126 may facilitate characterizing and/or quantifying an opportunity associated with each candidate trajectory 180, for example, in order to select one or more candidate trajectories 180 to implement.
The sidetrack risk engine 126 may characterize an opportunity for a candidate trajectory 180 based on determining an opportunity value 182 for that trajectory. For example, the opportunity value(s) 182 for a candidate trajectory 180 may include and/or may be determined based on assessing various factors that contribute to, as well as inhibit, a value proposition of the opportunity. In some embodiments, the opportunity values 182 are determined by considering a cost for implementing a given candidate trajectory 180. For instance, the sidetrack risk engine 126 may determine or estimate a dollar amount associated with preparing the existing (e.g., host) wellbore, drilling and completing the sidetrack wellbore, and producing resources from that sidetrack wellbore.
In some embodiments, the opportunity value(s) 182 are based on a time or duration for implementing a given candidate trajectory. For example, the sidetrack risk engine 126 may determine an amount of time that it will take to drill, complete, and begin producing resources from a given sidetrack wellbore.
In some embodiments, the opportunity value(s) 182 are based on a qualitative evaluation of risk of a given candidate trajectory 180. For example, the sidetrack risk engine 126 may implement a risk function for determining a risk value for a given candidate trajectory 180. In some embodiments, the qualitative risk is based on a deviation and/or tortuosity of the candidate trajectory 180. For instance, more deviated and/or tortuous wellbores may be less desirable and/or present more obstacles or risks. In some embodiments, the qualitative risk is based on a dog leg severity (DLS) required to implement a given candidate trajectory 180, which may reflect, for example, the risk associated with elevated DLS angles on downhole equipment. In other cases, the qualitative risk is based on a length of the wellbore, reflecting, for example, the fact that longer wellbores present more opportunity for challenges, failures, risk, etc. In some examples, the qualitative risk is based on a depth of an associated sidetrack zone for a candidate trajectory, such as an entry point of the offset wellbore or a depth where the potential offset wellbore begins from the host wellbore. This may reflect, for example the consideration that the shallower the entry point of the offset wellbore, the more of the host wellbore that is being abandoned, requiring significant removal of downhole components, weakening the host well, etc. In some embodiments, the qualitative risk is based on a production forecast for an offset wellbore to produce resources once completed and/or a lost production associated with abandoning a host wellbore in favor of the offset wellbore.
In some embodiments, the sidetrack risk engine 126 determines several opportunity values 182 for each candidate trajectory 180. For instance, the sidetrack risk engine 126 may determine an opportunity value associated with cost, time, and/or risk. In some embodiments, the sidetrack risk engine 126 determines a single opportunity value 182 for each candidate trajectory 180, for example, based on accounting for the cost factor, time factor, and qualitative risk factor. For example, each of these factors may be evaluated by the sidetrack risk engine 126 and may be expressed as a normalized value for the factor. The sidetrack risk engine 126 may implement an opportunity function (e.g., cost function) for evaluating the overall potential or opportunity value for the candidate trajectory 180. For instance, the opportunity function may weigh the various factors. The weights may be based on user input or preferences. For instance, in some cases, it may be desirable to evaluate the candidate trajectories 180 with more of a consideration toward cost than, for example, duration or risk. In other cases, it may be beneficial to more heavily weigh low-risk candidate trajectories, for example, over cost or time. In this way, the various candidate sidetrack trajectories 180 may be evaluated in order to quantify and characterize their potential or opportunity for implementation.
In some embodiments, the sidetrack identification system 120 may determine one or more (or all) candidate trajectories 180 and associated opportunity values 182 for a given host wellbore. In some embodiments, the sidetrack identification system 120 may determine one or more (or all) candidate trajectories 180 and associated opportunity values 182 for a set of multiple wellbores, for example, in a basin, oilfield, or catalogue of wellbores. Additionally, the candidate trajectories 180 and associated opportunity values 182 may be associated with reaching or accessing one target or multiple targets from the one or multiple different wellbores.
As mentioned, the sidetrack identification system 120 includes an opportunity manager 127. The opportunity manager 127 may facilitate ranking and/or selecting one or more sidetrack trajectories 186 for implementing in one or more wellbores.
In some embodiments, the opportunity manager 127 may rank or evaluate the candidate trajectories 180 based on the associated opportunity values 182. For example, the opportunity manager 127 may rank the candidate trajectories 180 based on one or more user- or application-specific objectives, such as by ranking the candidate trajectories based on cost, time, or risk. In some embodiments, the opportunity manager 127 may implement a cost function for evaluating the candidate trajectories 180 based on their opportunity values 182, for instance, in order to identify the candidate trajectories 180 that are desirable in many categories, or across all categories. In some embodiments, the cost function may weigh and/or discount certain factors or categories of the opportunity values 182 in order to identify candidate trajectories that fulfill certain objectives or priorities of a given operation.
In some embodiments, the opportunity manager 127 filters one or more candidate trajectories 180 based on one or more constraints 184. The constraints 184 may be user identified or application specific. For example, the opportunity manager 127 may filter out one or more candidate trajectories 180 that exceed a maximum budget and/or implementation time. In some embodiments, the opportunity manager 127 may filter one or more candidate trajectories 180 that do not meet a minimum production capacity. The opportunity manager 127 may filter one or more candidate trajectories 180 that exceed a maximum DLS and/or length. In some cases, candidate trajectories 180 may be filtered based on trajectories that are mutually exclusive, such as by originating from a same host well, or based on accessing a same target (e.g., from different host wells).
In some embodiments, the opportunity manager 127 may select a best or optimal sidetrack trajectory 186 for implementing in a given wellbore, based on the sidetrack trajectory 186 best fulfilling the specific requirements, constraints 184, and priorities for that wellbore, project, or operation.
In some embodiments, the opportunity manager 127 may identify a set of several sidetrack trajectories 186 for implementing in connection with a set of multiple wellbores. For example, the sidetrack identification system 120 may receive a set of multiple wellbores that are all within a same basin, oilfield, or client catalogue of wellbores. The sidetrack identification system 120 may identify the set of sidetrack trajectories 186 that may be optimal for implementing within the set of wellbores.
For example, consider a set of 10 wellbores located within an oilfield. It may be desirable to identify a set of sidetrack trajectories 186 for implementing at some (or all) of those wellbores in order to continue or increase production, access different reservoirs, etc. The sidetrack identification system 120 may evaluate those wellbores as described herein and may determine viable sidetrack zones for drilling sidetrack wellbores. The sidetrack identification system 120 may identify one or more (or all) potential candidate trajectories through those sidetrack zones for each of the set of 10 wellbores and for accessing one or multiple different underground targets. Thus, a large collection of candidate sidetrack trajectories 180 may be possible from this set of wellbores.
As described herein, for each candidate sidetrack trajectory 180, the sidetrack identification system 120 may determine one or more opportunity values 182 for characterizing and/or quantifying an opportunity associated with each candidate trajectory 180. Based on the opportunity values 182, the sidetrack identification system 120 may evaluate the candidate sidetrack trajectories 180 as a whole, and may identify the set of sidetrack trajectories 186 that, as a whole, best meet the total objectives of a given operation in order that those trajectories may be implemented in one or more of the wellbores.
For example, the set of sidetrack trajectories 186 may be selected based on the entire set being drillable within a total budget (e.g., rather than evaluating budget on an individual sidetrack basis). For instance, a first sidetrack trajectory for a first wellbore may be relatively expensive to implement, but given other favorable factors (production, length, time, etc.), the sidetrack identification system 120 may determine that it may nevertheless be desirable to implement the first sidetrack trajectory despite it consuming a larger portion of the budget. Making this determination, however, may require implementing relatively cheaper sidetrack trajectories in one or more other wellbores, even at the expense of those cheaper sidetrack trajectories being somewhat less favorable than sidetrack trajectories that could otherwise be drilled at those wellbores. Nevertheless, the sidetrack identification system 120 may determine that this set of sidetrack trajectories is optimal based on the entire set best fulfilling certain objectives, such as production, time, risk, etc. and while also following one or more constraints, such as a total budget. Similar considerations may be made for selecting the best set of sidetrack trajectories 186 based on a total production forecast, for the set of trajectories 186. In another example, the set of sidetrack trajectories 186 may be selected based on being best drillable by a (e.g., offshore) drill rig, which may sequentially drill each sidetrack one after another. In this way, the sidetrack identification system 120 may not necessarily select the best or most optimal candidate trajectory 180 for each wellbore, but rather may identify the set of candidate trajectories that, as a whole, are more optimal with respect to the objectives, constraints, and weighted priorities for a given operation. For instance, in some cases, the set of trajectories 186 may not include a trajectory for implementing at each wellbore of the set of wellbores, but rather, the sidetrack identification system 120 may determine that the budget for time, cost, etc., may best be spent implementing a set of trajectories at less than all available wellbores.
In some embodiments, the method 700 includes an act 710 of receiving hole-casing data.
In some embodiments, the method 700 includes an act 720 of determining one or more candidate sidetrack zones based on identifying cement overlap areas from the hole-casing data. For example, the candidate sidetrack zones may be defined by one or more areas of a single layer of casing cemented to the open wellbore. In some embodiments the sidetrack identification system reduces one or more of the candidate sidetrack zones based on an associated casing having a casing depth above a shallow casing threshold. For example, the sidetrack identification system may reduce one or more of the candidate sidetrack zones to a single point. The single point may be a lowest point in the candidate sidetrack zone.
In some embodiments, the method 700 includes an act 730 of receiving completion data for one or more completion elements. The one or more completion elements may include a production packer.
In some embodiments, the method 700 includes an act 740 of determining a completion depth for each of the one or more completion elements based on the completion data.
In some embodiments, the method 700 includes an act 750 of selecting one or more sidetrack zones by filtering the one or more candidate sidetrack zones based on one or more of the completion depths. In some embodiments, the method 700 includes receiving cementing data. The sidetrack identification system may filter the one or more candidate sidetrack zones based on the cementing data. For example, the sidetrack identification system may determine a cement quality for one or more areas of the wellbore and may filter out one or more candidate sidetrack zones not associated with areas of good cement quality. In some embodiments, the sidetrack identification system filters out one or more candidate sidetrack zones below the completion depth of the production packer. In some embodiments, the sidetrack identification system receives target data and filters the one or more candidate sidetrack zones based on the target data. For example, the sidetrack identification system may determine one or more trajectories to reach a target through one or more of the candidate sidetrack zones. The sidetrack identification system may select a sidetrack trajectory of the one or more sidetrack trajectories based on a cost function for accessing the target. In some embodiments, the method 700 includes causing the selected sidetrack trajectory to be implemented in a downhole drilling operation.
In some embodiments, the sidetrack identification system performs the method 700 for a plurality of underground wellbores in parallel. For example, the method 700 may be performed for at least 50 underground wellbores in parallel. In some embodiments, the sidetrack identification system performs the method 700 in under 1 minute. For example, the method 700 may be performed for a plurality of underground wellbores in parallel in under 1 minute. In some embodiments, the sidetrack identification system performs the method 700 automatically and without user input.
Turning now to
The computer system 800 includes a processor 801. The processor 801 may be a general-purpose single- or multi-chip microprocessor (e.g., an Advanced RISC (Reduced Instruction Set Computer) Machine (ARM)), a special purpose microprocessor (e.g., a digital signal processor (DSP)), a microcontroller, a programmable gate array, etc. The processor 801 may be referred to as a central processing unit (CPU). Although just a single processor 801 is shown in the computer system 800 of
The computer system 800 also includes memory 803 in electronic communication with the processor 801. The memory 803 may include computer-readable storage media and can be any available media that can be accessed by a general purpose or special purpose computer system. Computer-readable media that store computer-executable instructions are non-transitory computer-readable media (device). Computer-readable media that carry computer-executable instructions are transmission media. Thus, by way of example and not limitations, embodiment of the present disclosure can comprise at least two distinctly different kinds of computer-readable media: non-transitory computer-readable media (devices) and transmission media.
Both non-transitory computer-readable media (devices) and transmission media may be used temporarily to store or carry software instructions in the form of computer readable program code that allows performance of embodiments of the present disclosure. Non-transitory computer-readable media may further be used to persistently or permanently store such software instructions. Examples of non-transitory computer-readable storage media include physical memory (e.g., RAM, ROM, EPROM, EEPROM, etc.), optical disk storage (e.g., CD, DVD, HDDVD, Blu-ray, etc.), storage devices (e.g., magnetic disk storage, tape storage, diskette, etc.), flash or other solid-state storage or memory, or any other non-transmission medium which can be used to store program code in the form of computer-executable instructions or data structures and which can be accessed by a general purpose or special purpose computer, whether such program code is stored or in software, hardware, firmware, or combinations thereof.
Instructions 805 and data 807 may be stored in the memory 803. The instructions 805 may be executable by the processor 801 to implement some or all of the functionality disclosed herein. Executing the instructions 805 may involve the use of the data 807 that is stored in the memory 803. Any of the various examples of modules and components described herein may be implemented, partially or wholly, as instructions 805 stored in memory 803 and executed by the processor 801. Any of the various examples of data described herein may be among the data 807 that is stored in memory 803 and used during execution of the instructions 805 by the processor 801.
A computer system 800 may also include one or more communication interfaces 809 for communicating with other electronic devices. The communication interface(s) 809 may be based on wired communication technology, wireless communication technology, or both. Some examples of communication interfaces 809 include a Universal Serial Bus (USB), an Ethernet adapter, a wireless adapter that operates in accordance with an Institute of Electrical and Electronics Engineers (IEEE) 802.11 wireless communication protocol, a Bluetooth® wireless communication adapter, and an infrared (IR) communication port.
The communication interfaces 809 may connect the computer system 800 to a network. A “network” or “communications network” may generally be defined as one or more data links that enable the transport of electronic data between computer systems and/or modules, engines, and/or other electronic devices. When information is transferred or provided over a communication network or another communications connection (either hardwired, wireless, or a combination of hardwired or wireless) to a computing device, the computing device properly views the connection as a transmission medium. Transmission media can include a communication network and/or data links, carrier waves, wireless signals, and the like, which can be used to carry desired program or template code means or instructions in the form of computer-executable instruction or data structures and which can be accessed by a general purpose or special purpose computer.
A computer system 800 may also include one or more input devices 811 and one or more output devices 813. Some examples of input devices 811 include a keyboard, mouse, microphone, remote control device, button, joystick, trackball, touchpad, and lightpen. Some examples of output devices 813 include a speaker and a printer. One specific type of output device that is typically included in a computer system 800 is a display device 815. Display devices 815 used with embodiments disclosed herein may utilize any suitable image projection technology, such as liquid crystal display (LCD), light-emitting diode (LED), gas plasma, electroluminescence, or the like. A display controller 817 may also be provided, for converting data 807 stored in the memory 803 into text, graphics, and/or moving images (as appropriate) shown on the display device 815.
The various components of the computer system 800 may be coupled together by one or more buses, which may include a power bus, a control signal bus, a status signal bus, a data bus, etc. For the sake of clarity, the various buses are illustrated in
The techniques described herein may be implemented in hardware, software, firmware, or any combination thereof, unless specifically described as being implemented in a specific manner. Any features described as modules, components, or the like may also be implemented together in an integrated logic device or separately as discrete but interoperable logic devices. If implemented in software, the techniques may be realized at least in part by a non-transitory processor-readable storage medium comprising instructions that, when executed by at least one processor, perform one or more of the methods described herein. The instructions may be organized into routines, programs, objects, components, data structures, etc., which may perform particular tasks and/or implement particular data types, and which may be combined or distributed as desired in various embodiments.
Further, upon reaching various computer system components, program code in the form of computer-executable instructions or data structures can be transferred automatically or manually from transmission media to non-transitory computer-readable storage media (or vice versa). For example, computer executable instructions or data structures received over a network or data link can be buffered in memory (e.g., RAM) within a network interface module (NIC), and then eventually transferred to computer system RAM and/or to less volatile non-transitory computer-readable storage media at a computer system. Thus, it should be understood that non-transitory computer-readable storage media can be included in computer system components that also (or even primarily) utilize transmission media.
In some embodiments, a downhole system is used for drilling an earth formation to form a wellbore. The downhole system includes a drill rig used to turn a drilling tool assembly which extends downward into the wellbore. The drilling tool assembly may include a drill string, a bottomhole assembly (“BHA”), and a bit, attached to the downhole end of the drill string.
The drill string may include several joints of drill pipe connected end-to-end through tool joints. The drill string transmits drilling fluid through a central bore and transmits rotational power from the drill rig to the BHA. In some embodiments, the drill string further includes additional downhole drilling tools and/or components such as subs, pup joints, etc. The drill pipe provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid discharges through selected-size nozzles, jets, or other orifices in the bit for the purposes of cooling the bit and cutting structures thereon, and for lifting cuttings out of the wellbore as it is being drilled.
The BHA may include the bit, other downhole drilling tools, or other components. An example BHA may include additional or other downhole drilling tools or components (e.g., coupled between to the drill string and the bit). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing.
In general, the downhole system may include other downhole drilling tools, components, and accessories such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). Additional components included in the downhole system may be considered a part of the drilling tool assembly, the drill string, or a part of the BHA, depending on their locations in the downhole system.
The bit in the BHA may be any type of bit suitable for degrading downhole materials. For instance, the bit may be a drill bit suitable for drilling the earth formation 101. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits. In other embodiments, the bit may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit may be used with a whipstock to mill into casing lining the wellbore. The bit may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to the surface, or may be allowed to fall downhole. The bit may include one or more cutting elements for degrading the earth formation.
The BHA may further include a rotary steerable system (RSS). The RSS may include directional drilling tools that change a direction of the bit, and thereby the trajectory of the wellbore. At least a portion of the RSS may maintain a geostationary position relative to an absolute reference frame, such as gravity, magnetic north, and/or true north. Using measurements obtained with the geostationary position, the RSS may locate the bit, change the course of the bit, and direct the directional drilling tools on a projected trajectory. The RSS may steer the bit in accordance with or based on a trajectory for the bit. For example, a trajectory may be determined for directing the bit toward one or more subterranean targets such as an oil or gas reservoir.
The downhole system may include one or more client devices with a sidetrack identification system implemented thereon (e.g., implemented on one, several, or across multiple client devices). The sidetrack identification system may facilitate determining or identifying one or more sidetrack windows or sidetrack zones for drilling sidetrack wellbores off of the wellbore. In some embodiments, the sidetrack identification system facilitates determining and/or selecting one or more trajectories for accessing a downhole target through one or more of the identified sidetrack zones.
As mentioned above, one or more sections of the wellbore may be lined with casing. The casing may be implemented in various stages, including various types of casing. For example, several sequential stages of casing may have successively smaller diameters and may be positioned inside of each other as the wellbore deepens. In this way, the casing may extend down into the earth in a telescoping manner. The stages of the casing may each serve distinct purposes, such as to safeguard against environmental contamination, maintain structural stability, isolate different geological formations, etc.
The casing may be fixed in place by cementing the casing with a cement. For example, after drilling a portion of the wellbore, one or more sections of the casing may be positioned within the wellbore, and the cement may be pumped down through the casing and up through the annular space surrounding the outer diameter of the casing. In this way, the casing may be cemented directly to the open wellbore, to a previously installed (e.g., outer) casing, or a combination of both. The casing may be fixed in place in this manner to provide structural support to prevent the collapse of the wellbore wall, may maintain wellbore integrity by isolating different geological formations, and/or may act as a conduit for fluids such as drilling mud and production fluids.
In some embodiments, the casing includes a conductor casing. The conductor casing may be an outermost casing string. The conductor casing may be cemented to the wellbore, and may extend from the surface down to a relatively shallow depth. The conductor casing may be installed at the very beginning of the drilling process and may provide structural support and stability to the wellbore during drilling.
In some embodiments, the casing includes a surface casing. The surface casing may be positioned at least partly inside of, and may extend from, the conductor casing. The surface casing may be installed after the initial drilling of the shallow sections of the wellbore to protect the relatively shallow formations from the drilling, operation, and/or production of the wellbore. For example, the surface casing may be cemented in place and may create a secure barrier between the wellbore and the surrounding formations to protect shallow aquifers and prevent contamination of groundwater. The surface casing may also provide stability to the upper portions of the wellbore. The surface casing may be cemented to the open wellbore at one or more locations, and may also be cemented (e.g., at an upper portion) to the conductor casing. In this way, at least some of an overlapping portion of the conductor casing and the surface casing may exhibit several (e.g., 2) layers of cement from an installation of each respective stage of casing.
In some embodiments, the casing includes an intermediate casing. The intermediate casing may be a stage of the casing that is below the surface casing but above a production zone. The intermediate casing may be positioned at least partly inside of, and may extend from, the surface casing. The intermediate casing may provide support for formations that may have high pressures, unstable rock structures, or other challenging conditions. The intermediate casing may be cemented to create a seal and to isolate different geological zones to prevent fluid migration. Similar to the surface casing, the intermediate casing may be cemented to the open wellbore at one or more locations, and may also be cemented (e.g., at an upper portion) to the surface casing. Thus, in some embodiments, an overlapping portion of the intermediate casing with the surface casing exhibits several layers of cement from an installation of each respective stage of casing.
In some embodiments, the casing includes a production casing. The production casing may be an innermost stage of the casing and may be installed to reach the target, or the production zone. The production casing may be configured to withstand the high pressures and temperatures associated with the production of hydrocarbons or other resources from the production zone. The production casing may also facilitate maintaining the integrity of the wellbore during the extraction phase of the downhole system. Similar to the surface casing and the intermediate casing, the production casing may be cemented to the open wellbore in the production zone at one or more locations, and may also be cemented (e.g., at an upper portion) to the intermediate casing. Thus, in some embodiments, an overlapping portion of the production casing with the intermediate casing exhibits several layers of cement from an installation of each respective stage of casing.
As mentioned, each of the stages of the casing may extend at least partially into a previous stage of the casing. In some embodiments, one or more stages extend all the way to the surface. For example, one or more of the production casing, the intermediate casing, and the surface casing may extend (e.g., through the previous stage) to the surface. In some embodiments, one or more stages of the casing do not extend fully to the surface, such as a casing liner. For example, hangers, slips, seals, packers, etc. of a casing hanger assembly may be positioned near the bottom of a previous stage of the casing, and the subsequent stage may be connected and/or sealed to the previous stage by the hanger assembly. The casing liner may be cemented to the wellbore as described herein. In this way one or more stages of the casing may be implemented as a casing liner and may be hung from a previous stage. In some embodiments, one or more components of the hanger assembly are otherwise implemented to support, connect, secure, center, etc. the stages of casing that do extend fully to the surface.
In some embodiments, one or more locations of the wellbore exhibit multiple layers of cement due to multiple successive stages of the casing. For example, an entirety of the annular space surrounding the outer diameter of a stage of casing may be cemented to the wellbore and/or to the previous, outer stage of casing. For instance, the surface casing may be cemented to the wellbore at a lower portion and cemented to the conductor casing at an upper section. In another example, a stage of casing may be cemented up until the stage overlaps the previous stage of casing. For instance, the production casing and the intermediate casing may be cemented to the wellbore, with little or no cement in the annular space between successive stages of the casing. In some embodiments, a portion of the overlapping area between stages is cemented such that some of one stage is cemented to a previous stage of the casing. In this way, one or more locations may exhibit multiple layers of cement at a same depth of the wellbore.
In some embodiments, a production tubing is implemented in the wellbore. The production tubing may facilitate the extraction of hydrocarbons from underground reservoirs. For example, the production tubing may be a conduit through which hydrocarbons may flow from the production zone to the surface so they can be collected and processed. The production tubing may be run into the wellbore and may be secured in place and configured with various components such as hangars, packers, valves, joints, etc. In some embodiments, a production packer is implemented in the wellbore. The production packer may facilitate isolating the production zone from one or more other geological zones or formations. For example, the production packer may be positioned in and may seal the annular space between the intermediate casing and the production tubing. In this way the production packer may facilitate containing a reservoir pressure of the production zone in order to control the flow of hydrocarbons through the production tubing.
The casing may be implemented in the wellbore in accordance with any of the techniques described herein, or any other techniques, and combinations thereof. Additionally, the techniques of the present disclosure should be understood as applying to any type of onshore or offshore wellbore.
In some embodiments, a sidetrack identification system may be implemented in an example environment in accordance with one or more embodiments described herein. In some embodiments, the environment includes one or more server device(s). The server device(s) may include one or more computing devices (e.g., including processing units, data storage, etc.) organized in an architecture with various network interfaces for connecting to and providing data management and distribution across one or more client systems. The server devices may be connected to and may communicate with (either directly or indirectly) one or more client devices through a network. The network may include one or multiple networks and may use one or more communication platforms or technologies suitable for transmitting data. The network may refer to any data link that enables transport of electronic data between devices of the environment. The network may refer to a hardwired network, a wireless network, or a combination of a hardwired network and a wireless network. In one or more embodiments, the network includes the internet. The network may be configured to facilitate communication between the various computing devices via well-site information transfer standard markup language (WITSML) or similar protocol, or any other protocol or form of communication.
The client device may refer to various types of computing devices. For example, one or more client devices may include a mobile device such as a mobile telephone, a smartphone, a personal digital assistant (PDA), a tablet, a laptop, or any other portable device. Additionally, or alternatively, the client devices may include one or more non-mobile devices such as a desktop computer, server device, surface or downhole processor or computer (e.g., associated with a sensor, system, function, etc. of the downhole system), or other non-portable device. In one or more implementations, the client devices include graphical user interfaces (GUI) thereon (e.g., a screen of a mobile device). In addition, or as an alternative, one or more of the client devices may be communicatively coupled (e.g., wired or wirelessly) to a display device having a graphical user interface thereon for providing a display of system content. The server device(s) may similarly refer to various types of computing devices. Each of the devices of the environment may include features and functionalities described below.
The environment may include a sidetrack identification system implemented on one or more computing devices. The sidetrack identification system may be implemented on one or more client device, server devices, and combinations thereof. Additionally, or alternatively, the sidetrack identification system may be implemented across the client devices and the server devices such that different portions or components of the sidetrack identification system are implemented on different computing devices in the environment. In this way, the environment may be a cloud computing environment, and the sidetrack identification system may be implemented across one or more devices of the cloud computing environment in order to leverage the processing capabilities, memory capabilities, connectivity, speed, etc. that such cloud computing environments offer in order to facilitate the features and functionalities described herein.
The sidetrack identification system may include a data manager, a sidetrack zone engine, a filtering engine, a trajectory manager, a sidetrack risk engine, and an opportunity manager. The sidetrack identification system may also include a data storage having hole-casing data, completion data, cementing data, target data, sidetrack zones, candidate sidetrack trajectories, opportunity values, constraints, and sidetrack trajectories, stored thereon. While one or more embodiments described herein describe features and functionalities performed by specific components of the sidetrack identification system, it will be appreciated that specific features described in connection with one component of the sidetrack identification system may, in some examples, be performed by one or more of the other components of the sidetrack identification system.
By way of example, one or more of the data receiving, gathering, and/or storing features of the data manager may be delegated to other components of the sidetrack identification system. As another example, while candidate sidetrack zones may be determined and/or adjusted by the sidetrack zone engine, in some instances, some or all of these features may be performed by the filtering engine (or other component of the sidetrack identification system). Indeed, it will be appreciated that some or all of the specific components may be combined into other components and specific functions may be performed by one or across multiple of the components of the sidetrack identification system.
Additionally, while the sidetrack identification system has been described as being implemented on a client device of (or associated with) the downhole system, it should be understood that some or all of the features and functionalities of the sidetrack identification system may be implemented on or across multiple client devices and/or server devices. For example, data may be input and/or received by the data manager on a (e.g., local) client device, and one or more sidetrack zones may be identified by the sidetrack zone engine on a remote, server, and/or cloud device. Indeed, it will be appreciated that some or all of the specific components may be implemented on or across multiple client devices and/or server devices, including individual functions of a specific component being performed across multiple devices.
As mentioned above, the sidetrack identification system includes a data manager. The data manager may receive and manage a variety of types of data of the sidetrack identification system, such as hole-casing data, completion data, and/or cementing data.
As just mentioned, the data manager may receive hole-casing data. The hole-casing data may include information related to one or more sections, stages, and/or components associated with the casing installed in the wellbore. For example, the hole-casing data may include information related to one or more stages of the casing, such as the conductor casing, surface casing, intermediate casing, and/or production casing as described herein. The hole-casing data may include information related to other components associated with the casing and/or the wellbore such as a tieback, or any other component. The hole-casing data may identify an associated hole size (e.g., diameter), hole end measurement depth (MD), casing size, casing start MD, casing end MD, top MD of the cement of the associated component, drift inner diameter, and combinations thereof. The hole-casing data may include any other information associated with the casing.
As mentioned, the data manager may receive completion data. The completion data may include information related to one or more completion components or completion elements associated with a completion of the wellbore. For example, the completion data may include information related to various sections of tubing (e.g., production tubing), valves, packers, or any other completion element associated with the completion of the wellbore. The completion data may identify a top MD, length, inner diameter, outer diameter, drift inner diameter, and combinations thereof. The completion data may include any other information associated with the completion of the wellbore.
As mentioned, the data manager may receive cementing data. The cementing data may include information related to the cement implemented to fix one or more components within the wellbore. For example, the cementing data may identify a start and end depth, as well as a quality for one or more sections of the cement. In some embodiments, the cementing data identifies an associated component for the section(s) of cement identified in the cementing data. The cementing data may include any other information associated with the cement.
In some embodiments, the data manager receives target data. The target data may include information related to a subterranean target for the wellbore and/or for one or more sidetrack wellbores. For example, the target data may indicate a location, distance, boundary, orientation, size, and/or shape of an underground reservoir which the wellbore and/or one or more sidetrack wellbores may potentially access. The target data may identify a formation, substance, capacity, production zone, etc. for the reservoir. The target data may include any other information associated with one or more underground targets.
In some embodiments, the data manager receives user input. The data manager may receive the user input, for example, via any of the client devices and/or server devices. Any of the data described herein may be input or augmented via the user input. For example, in some instances, some or all of the sensor data is received by the data manager as user input. In some instances, some or all of the hole-casing data, completion data, and/or cementing data is received by the data manager as user input. The user input may be received in association with one or more functions or features of the sidetrack identification system, such as part of determining and/or selecting a sidetrack window or trajectory. In this way, the data manager may receive the user input to the sidetrack identification system.
In this way, the sidetrack identification system may receive any of a variety of types of data. The data manager may save and/or store any of the data it receives to the data storage. While the data manager has been described as receiving data associated with the wellbore, this reference to one singular wellbore is merely for illustrative purposes of the techniques described herein. In some embodiments, the data manager receives data for many wellbores, such as up to 50 or 100 wellbores. Indeed, as described herein, the sidetrack identification system may receive and utilize data from any number of wellbores in order to provide the sidetrack zone detection features and functionalities described herein for each wellbore in parallel and/or simultaneously.
In some embodiments, the data manager cleans some or all of the data. For example, the data manager may receive data in a variety of forms. The data manager may profile the data to understand its structure, format, quality, etc. Based on the profiling, the data manager may check for issues such as missing values, duplicate entries, outliers, inconsistent formats, etc. The data manager may validate the data against one or more predefined rules and/or standards such as verifying that data is in an expected format or falls within an expected range. In some embodiments, the data manager addresses any errors or inconsistencies. For example, the data manager may remove incorrect, inconsistent, or duplicate entries. In another example, the data manager may correct incorrect, inconsistent, or missing entries, such as by estimating or averaging values based on an associated context. In another example, the data manager may standardize the format or transform the format of the data for consistency. In another example, the data manager may flag data issues for manual review and/or may facilitate a user correcting data issues. In this way, the data manager may facilitate identifying and/or correcting errors, inconsistencies, or inaccuracies in the data to make the data more reliable and useful.
In some embodiments, the data manager extracts and/or converts some or all of the data from various sources. For example, the data manager may receive some or all of the hole-casing data, completion data, and/or target data as reports, images, PDFs, or other documents and/or in one or more other formats. The data manager may extract the data from these files, for example, through optical character recognition (OCR) or other extraction technique. In some cases, the data manager converts or exports the (e.g., extracted) data to a universal and/or industry standard format. For example, the data manager may save the data to an open subsurface data universe (OSDU) format or standard. The data may be stored at a server in the OSDU format and may be recalled and/or accessed by the various components of the sidetrack identification system in this format. The data manager may store the data in any other format or according to any other standard. In some embodiments, the data manager accesses the data in this format, for example, as extracted and/or converted by another system or user.
In some embodiments, the data manager constructs a graph, plot, image, or other representation. For example, based on any of the data that it receives, the data manager may generate a plot of some or all of the wellbore. The plot may illustrate and/or represent one or more aspects of the wellbore associated with the workflow of the sidetrack identification system described herein. For example, the plot may represent the casing, completion, cement, surface, depth, length, diameter, or any other aspect of the wellbore, and combinations thereof. The plot may represent one or more candidate sidetrack zones, including one or more adjustments or modifications to the candidate sidetrack zones as described herein. The plot may be to scale, or may be sectioned, exaggerated, zoomed, conceptualized, diagramed, or represented in any other way. In some embodiments, the data manager presents the plot via a graphical user interface (GUI).
As mentioned, the sidetrack identification system includes a sidetrack zone engine. The sidetrack zone engine may identify one or more candidate sidetrack zones for the wellbore. The sidetrack zone engine may initially take the entirety of the length of the wellbore as a candidate sidetrack zone, and may segment, reduce, limit, or otherwise adjust the candidate sidetrack zone based on the hole-casing data.
In some embodiments, the sidetrack zone engine identifies candidate sidetrack zones as areas of the wellbore exhibiting a single layer of cement. For example, the sidetrack zone engine may access the hole-casing data from the data storage. The sidetrack zone engine may compare one or more of the MDs identified in the hole-casing data associated with a specific component, section, or stage of the casing, and may determine one or more cement overlap areas between the cement associated with one component, and the cement associated with another component. For instance, a layer of cement may be present from a MD of 171 m to a MD of 286 m, in connection with the conductor casing. Additionally, another layer of cement may be present from a MD of 215 m to a MD of 1339 m in association with the surface casing. The sidetrack zone engine may accordingly identify a cement overlap area from 215 m to 286 m based on the wellbore exhibiting 2 layers of cement in association with the overlapping of the conductor casing and the surface casing. Accordingly, the sidetrack zone engine may remove the cement overlap area from 215 m to 286 m from the candidate sidetrack zone. Similarly, the sidetrack zone engine may identify cement overlap areas from a MD of 1298 m to a MD of 1339, as well as from a MD of 2943 to a MD of 2981 based on the hole-casing data. The sidetrack zone engine may accordingly remove these cement overlap areas from the candidate sidetrack zone.
In this way, the sidetrack zone engine may determine one or more candidate sidetrack zones based on removing certain areas or depths in order to avoid potential obstacles or obstructions when drilling or initiating a sidetrack wellbore. For example, in some cases drilling through the cement may be difficult, may damage or wear one or more components, may be time-consuming, or may otherwise be undesirable. The sidetrack zone engine may accordingly remove the cement overlap areas in order to reduce the amount of cement to be drilled through.
As mentioned above, the sidetrack identification system includes a filtering engine. The filtering engine may filter one or more of the candidate sidetrack zones, including further adjusting or modifying the candidate sidetrack zones.
In some embodiments, the filtering engine filters and/or adjust the candidate sidetrack zones based on the cementing data 136. For example, the cementing data may indicate a quality of the cement at one or more locations. For instance, the cementing data may indicate that the cement of the intermediate liner from a MD of 2026 to a MD of 2647 is of “questionable” quality. Similarly, the cementing data 136 may indicate that the cement of the production liner from a MD of 4043 to a MD of 5053 is of “bad” quality. The cement may be indicated as “questionable” quality or “bad” for a variety of reasons. For example, cement quality issues may be associated with water contamination, setting issues, improper mixing, poor displacement, poor coverage, extreme temperatures and pressures, inadequate curing, operational errors, or any other circumstances that may compromise the quality of the cement. The filtering engine may accordingly flag these areas based on the cement not being of “good” quality.
In some embodiments, poor cement quality is accompanied by various issues with the wellbore. For example, poor cement quality can lead to inadequate zonal isolation, gas or fluid migration between geological zones or formations, casing corrosion or damage, loss of wellbore stability, reduces production efficiency, and safety and environmental risk, among other issues. Drilling sidetrack wellbores at or through these areas of poor cement quality may cause or exacerbate one or more of these issues. Accordingly, in some embodiments, the filtering engine removes the “questionable” cement quality areas and/or the “bad” cement quality areas from the candidate sidetrack zones.
In some embodiments, the filtering engine filters and/or adjust the candidate sidetrack zones based on the completion data. As discussed above, the completion data may indicate the location of one or more completion elements associated with a completion of the wellbore, such as the production packer. In some cases, it may be dangerous, prohibited, or otherwise undesirable to drill sidetrack wells at, near, or below one or more of the completion elements. For example, as mentioned above, the production packer may be a critical component that seals off and isolates the production zone from other parts of the wellbore. In some embodiments, drilling below the production packer can damage and/or compromise the integrity of the production packer leading to pressure loss and/or cross-contamination between geological zones. In other examples, drilling below the production packer may risk introducing drilling fluids, cuttings, and other materials into the production zone which may contaminate the reservoir, affect production quality, and/or pose safety risks. Further, drilling below the production packer may cause a loss of well control, which can lead to uncontrolled pressure releases, blowouts, or other emergency situations which may be highly dangerous and may result in significant safety risks and/or environmental damage. Additionally, in some cases, drilling below the production packer 166 is prohibited by local operational and/or environmental regulations. In some cases, drilling at, below, and/or through the production packer may be time-consuming and uneconomical.
In some embodiments, the filtering engine identifies the location of the completion elements (e.g., production packer), as well as an associated threshold, limit or boundary associated with the completion elements. For example, the production packer may be located at a MD of 2900 m, and may represent a lower boundary for which sidetrack wellbores may be drilled. The filtering engine may accordingly filter out and/or adjust one or more candidate sidetrack zones based on this boundary.
In some embodiments, the filtering engine filters and/or adjusts the candidate sidetrack zones based on the hole-casing data. For example, the filtering engine may identify, from the hole-casing data, a type of one or more of the sections of casing and an associated depth. Based on the type and/or depth, the filtering engine may accordingly make an adjustment to the candidate sidetrack zones. For example, in some cases, drilling sidetrack wellbores in certain types of casings (e.g., conductor casings or surface casings), or in casings at or above a threshold depth (e.g., shallow casings) may be dangerous, may not be feasible, or may otherwise be inopportune or undesirable. For instance, shallow casings located near the surface of the wellbore (e.g., within 1200 m) may have limited space for drilling tools, equipment, and/or wellbore geometry making it challenging to maneuver and operate drilling equipment effectively. In another example, shallow casing may be more prone to instability due to loose or unconsolidated formations near the surface which may increase the risk of wellbore collapse, damage to the casing, etc. Further, shallow formations may not provide adequate pressure containment, which may present well control issues such as blowouts. In another example, shallow drilling operations may risk contamination of groundwater and/or surface water, presenting significant environmental concerns. In some cases, shallow drilling may even be subject to additional environmental regulations and considerations.
In some embodiments, the filtering engine identifies the location of one or more specific types of casing and/or one or more relevant threshold depths. For example, the filtering engine may identify the surface casing as a shallow casing. In another example, the filtering engine may identify a threshold depth at about 1250 m. The filtering engine may accordingly restrict or limit one or more candidate sidetrack zones associated with the surface casing and/or above the threshold depth. In some embodiments, the filtering engine removes or reduces the candidate sidetrack zones for the surface casing. In some embodiments, the filtering engine removes or reduces the candidate sidetrack zones at or above the threshold depth. In some embodiments, the filtering engine does not remove a candidate sidetrack zone entirely, but reduces an applicable candidate sidetrack zone to a single point or single depth. For example, the filtering engine may reduce a candidate sidetrack zone for the surface casing to a single point or window at about 1300 m.
In this way, the filtering engine may receive the candidate sidetrack zones and may filter, adjust, or otherwise manipulate one or more of the candidate sidetrack zones in order to identify one or more favorable areas to drill sidetrack wellbores based on a variety of criteria. The filtering engine may store the candidate sidetrack zones (at any of the various stages of filtering and/or adjusting) to the data storage as sidetrack zones.
While the various filtering and adjusting functionalities of the filtering engine have been described in succession, in stages, or otherwise in relation to each other it should be understood that the filtering engine may perform one or more (or all) of the functionalities described herein in combination, in isolation, in any order, or not at all. For example, while the filtering engine has been described as filtering the candidate sidetrack zones based on the production packer after filtering based on the cementing data, it should be understood that the filtering based on the cementing data may be performed after the filtering based on the production packer, or in some cases, not at all. Indeed, any of the functionalities of the filtering engine and/or the sidetrack zone engine for determining the candidate sidetrack zones, such as based on the cementing data, completion elements, shallow casings, cement overlap areas, etc., may be performed in any order and in any combination.
In this way, the sidetrack identification system may determine one or more favorable sidetrack zones. In some embodiments, the sidetrack identification system determines the sidetrack zones quickly and efficiently. For example, the sidetrack identification system implemented in accordance with the environment described herein may facilitate determining the sidetrack zones for the wellbore in one minute or less, or even in as little as 12 seconds. In contrast, conventional, manual methods may be time-consuming and may take a drilling engineer up to 2 hours to complete. Thus, the efficiency provided by the computer and/or cloud computing nature of the sidetrack identification system may provide significant benefits over conventional, manual methods.
In some embodiments, the sidetrack identification system performs the features and functionalities described herein for a plurality of wellbores in parallel. For example, the sidetrack identification system may receive data for up to 50 or 100 wellbores and may determine the sidetrack zones for each of the wellbores simultaneously. The sidetrack identification system may additionally receive target data for multiple targets for each wellbore and may determine the sidetrack zones (and/or the trajectories as discussed below) for multiple targets for each wellbore. The sidetrack identification system may operate in parallel in this way in the same efficient manner, completing the workflow in as little as 12 seconds for all of the wellbores cumulatively. In this way, the efficiency advantages may be realized to an even greater degree when considering that the sidetrack identification system can achieve, in a matter of seconds, what may take a drilling engineer to 200 hours to achieve for 100 or more wellbores according to conventional techniques.
Further, the sidetrack identification system may provide accuracy advantages. For example, manual analysis and computation, regardless of the skill and knowledge of the operator, introduces the risk of mistakes, inconsistency, human error, fatigue, and other inaccuracies. The sidetrack identification system, however, may perform the features and functionalities described herein independently, automatically, and without user input. Thus, the accuracy and consistency of the computer-implemented sidetrack identification system may offer valuable accuracy benefits in addition to efficiency.
As mentioned above, the sidetrack identification system includes a trajectory manager. The trajectory manager may facilitate selecting a sidetrack zone, for example, for implementing a sidetrack trajectory for reaching or accessing a downhole target.
In some embodiments, the trajectory manager generates one or more trajectories. For example, the trajectory manager may access the target data and may identify one or more underground targets for accessing via one or more potential sidetrack wellbores. For example, an underground target may be a reservoir containing resources such as oil, gas, water, geothermal energy, or any other resource. An underground target may be a specific location or entry point of a reservoir, for example, to access a specific portion or store in a reservoir. The trajectory manager may access the target data for locating the underground target, and may access wellbore geometry data for identifying candidate trajectories for reaching or accessing the target(s) through the identified sidetrack zones.
In some embodiments, the trajectory manager identifies one or more candidate trajectories for a given wellbore. In some embodiments, the trajectory manager identifies one or more candidate trajectories for many wellbores of an oilfield, basin, or other catalogue of (e.g., existing) wellbores. In some embodiments, the trajectory manager determines all possible candidate trajectories for accessing one, or multiple downhole targets.
As mentioned, the sidetrack identification system includes a sidetrack risk engine. The sidetrack risk engine may facilitate characterizing and/or quantifying an opportunity associated with each candidate trajectory, for example, in order to select one or more candidate trajectories to implement.
The sidetrack risk engine may characterize an opportunity for a candidate trajectory based on determining an opportunity value for that trajectory. For example, the opportunity value(s) for a candidate trajectory may include and/or may be determined based on assessing various factors that contribute to, as well as inhibit, the value of the opportunity. In some embodiments, the opportunity values are determined by considering a cost for implementing a given candidate trajectory. For instance, the sidetrack risk engine may determine or estimate a dollar amount associated with preparing the existing (e.g., host) wellbore, drilling and completing the sidetrack wellbore, and producing resources from that sidetrack wellbore.
In some embodiments, the opportunity value(s) are based on a time or duration for implementing a given candidate trajectory. For example, the sidetrack risk engine 126 may determine an amount of time that it will take to drill, complete, and begin producing resources from a given sidetrack wellbore.
In some embodiments, the opportunity value(s) are based on a qualitative evaluation of risk of a given candidate trajectory. For example, the sidetrack risk engine may implement a risk function for determining a risk value for a given candidate trajectory. In some embodiments, the qualitative risk is based on a deviation and/or tortuosity of the candidate trajectory. For instance, more deviated and/or tortuous wellbores may be less desirable and/or present more obstacles or risks. In some embodiments, the qualitative risk is based on a dog leg severity (DLS) required to implement a given candidate trajectory, which may reflect the risk associated with elevated DLS angles on downhole equipment. In other cases, the qualitative risk is based on a length of the wellbore, reflecting the fact that longer wellbores present more opportunity for challenges, failures, risk, etc. In some examples, the qualitative risk is based on a depth of an associated sidetrack zone for a candidate trajectory, such as an entry point of the offset wellbore or a depth where the potential offset wellbore begins from the host wellbore. This may reflect the consideration that, the shallower the entry point of the offset wellbore, the more of the host wellbore that is being abandoned, requiring significant removal of downhole components, weakening the host well, etc. In some embodiments, the qualitative risk is based on a production forecast for an offset wellbore to produce resources once completed and/or a lost production associated with abandoning a host wellbore in favor of the offset wellbore.
In some embodiments, the sidetrack risk engine determines several opportunity values for each candidate trajectory. For instance, the sidetrack risk engine may determine an opportunity value associated with cost, time, and/or risk. In some embodiments, the sidetrack risk engine determines a single opportunity value for each candidate trajectory, for example, based on accounting for the cost factor, time factor, and qualitative risk factor. For example, each of these factors may be evaluated by the sidetrack risk engine and may be expressed as a normalized value for the factor. The sidetrack risk engine may implement an opportunity function (e.g., cost function) for evaluating the overall potential or opportunity value for the candidate trajectory. For instance, the opportunity function may weigh the various factors. The weights may be based on user input or preferences. For instance, in some cases, it may be desirable to evaluate the candidate trajectories with more of a consideration toward cost than, for example, duration or risk. In other cases, it may be beneficial to more heavily weight low-risk candidate trajectories, for example, over cost or time. In this way, the various candidate sidetrack trajectories may be evaluated in order to quantify and characterize their potential or opportunity for implementation.
In some embodiments, the sidetrack identification system may determine one or more (or all) candidate trajectories and associated opportunity values for a given host wellbore. In some embodiments, the sidetrack identification system may determine one or more (or all) candidate trajectories and associated opportunity values for a set of multiple wellbores, for example, in a basin, oilfield, or catalogue of wellbores. Additionally, the candidate trajectories and associated opportunity values may be associated with reaching or accessing one target or multiple targets from the one or multiple different wellbores.
As mentioned, the sidetrack identification system includes an opportunity manager. The opportunity manager may facilitate ranking and/or selecting one or more sidetrack trajectories for implementing in one or more wellbores.
In some embodiments, the opportunity manager may rank or evaluate the candidate trajectories based on the associated opportunity values. For example, the opportunity manager may rank the candidate trajectories based on one or more user- or application-specific objectives, such as by ranking the candidate trajectories based on cost, time, or risk. In some embodiments, the opportunity manager may implement a cost function for evaluating the candidate trajectories based on their opportunity values, for instance, in order to identify the candidate trajectories that are desirable in many categories, or across all categories. In some embodiments, the cost function may weigh and/or discount certain factors or categories of the opportunity values in order to identify candidate trajectories that fulfill certain objectives or priorities of a given operation.
In some embodiments, the opportunity manager filters one or more candidate trajectories 180 based on one or more constraints. The constraints may be user identified or application specific. For example, the opportunity manager may filter out one or more candidate trajectories that exceed a maximum budget and/or implementation time. In some embodiments the opportunity manager may filter one or more candidate trajectories that do not meet a minimum production capacity. The opportunity manager may filter one or more candidate trajectories that exceed a maximum DLS and/or length. In some cases, candidate trajectories may be filtered based on trajectories that are mutually exclusive, such as by originating from a same host well, or based on accessing a same target (e.g., from different host wells).
In some embodiments, the opportunity manager may select a best or optimal sidetrack trajectory for implementing in a given wellbore, based on the sidetrack trajectory best fulfilling the specific requirements, constraints, and priorities for that wellbore, project, or operation.
In some embodiments, the opportunity manager may identify a set of several sidetrack trajectories for implementing in connection with a set of multiple wellbores. For example, the sidetrack identification system may receive a set of multiple wellbores that are all within a same basin, oilfield, or client catalogue of wellbores. The sidetrack identification system may identify the set of sidetrack trajectories that may be optimal for implementing within the set of wellbores.
For example, consider a set of 10 wellbores located within an oilfield. It may be desirable to identify a set of sidetrack trajectories for implementing at some (or all) of those wellbores in order to continue or increase production, access different reservoirs, etc. The sidetrack identification system may evaluate those wellbores as described herein and may determine viable sidetrack zones for drilling sidetrack wellbores. The sidetrack identification system may identify one or more (or all) potential candidate trajectories through those sidetrack zones for each of the set of 10 wellbores and for accessing one or multiple different underground targets. Thus, a large collection of candidate sidetrack trajectories may be possible from this set of wellbores.
As described herein, for each candidate sidetrack trajectory, the sidetrack identification system may determine one or more opportunity values for characterizing and/or quantifying an opportunity associated with each candidate trajectory 180. Based on the opportunity values, the sidetrack identification system may evaluate the candidate sidetrack trajectories as a whole, and may identify the set of sidetrack trajectories 186 that, as a whole, best meet the total objectives of a given operation in order that those trajectories may be implemented in one or more of the wellbores.
For example, the set of sidetrack trajectories may be selected based on the entire set being drillable within a total budget (e.g., rather than evaluating budget on an individual sidetrack basis). For instance, a first sidetrack trajectory for a first wellbore may be relatively expensive to implement, but given other favorable factors (production, length, time, etc.), the sidetrack identification system may determine that it may nevertheless be desirable to implement the first sidetrack trajectory despite it consuming a larger portion of the budget. Making this determination, however, may require implementing relatively cheaper sidetrack trajectories in one or more other wellbores, even at the expense of those cheaper sidetrack trajectories being somewhat less favorable than sidetrack trajectories that could otherwise be drilled at those wellbores. Nevertheless, the sidetrack identification system may determine that this set of sidetrack trajectories is optimal based on the entire set best fulfilling certain objectives, such as production, time, risk, etc. and while also following one or more constraints, such as a total budget. Similar considerations may be made for selecting the best set of sidetrack trajectories based on a total production forecast, for the set of trajectories. In another example, the set of sidetrack trajectories may be selected based on being best drillable by a (e.g., offshore) drill rig, which may sequentially drill each sidetrack one after another. In this way, the sidetrack identification system may not necessarily select the best or most optimal candidate trajectory for each wellbore, but rather may identify the set of candidate trajectories that, as a whole, are more optimal with respect to the objectives, constraints, and weighted priorities for a given operation. For instance, in some cases, the set of trajectories may not include a trajectory for implementing at each wellbore of the set of wellbores, but rather, the sidetrack identification system may determine that the budget for time, cost, etc., may best be spent implementing a set of trajectories at less than all available wellbores. The trajectory manager may determine one or more (or all) potential trajectories through each of the sidetrack zones. Based on the potential trajectories, the trajectory manager may select a trajectory for implementing in connection with a sidetrack wellbore for accessing one or more targets. For example, the trajectory manager may determine various drilling parameters associated with each potential trajectory, such as a length, inclination, dog-leg severity, drilling properties and/or technique (e.g., weight on bit, rotary speed, mud weight, bit type and design, steering capabilities), associated formation properties, wellbore and completion plan, or any other relevant parameters or values. The trajectory manager may implement a cost function, algorithm, or model, for evaluating and selecting a trajectory. For example, the cost function may weigh the various parameters to facilitate selecting a trajectory that is optimal or best for implementing in connection with the downhole system. For instance, the cost function may select a trajectory based on an ease, speed, cost, expected resource production, etc. associated with the trajectory.
In this way, the trajectory manager may facilitate selecting a trajectory and/or a sidetrack zone. In some embodiments, the trajectory manager facilitates implementing the selected trajectory. For example, the trajectory manager may indicate to a user the selected trajectory and/or information or instructions for implementing the selected trajectory. In some embodiments, the trajectory manager may transmit the trajectory to one or more other systems for implementation in drilling a sidetrack wellbore.
In some embodiments, a method or a series of acts is implemented for identifying sidetrack zones in an underground wellbore as described herein, according to at least one embodiment of the present disclosure. In some embodiments, alternative embodiments may add to, omit, reorder, or modify any of the acts of the method. Alternatively, a non-transitory computer-readable storage medium may include instructions that, when executed by one or more processors, cause a computing device to perform the acts of the method. In still further implementations, a system can perform the acts of the method.
In some embodiments, the method includes an act of receiving hole-casing data.
In some embodiments, the method includes an act of determining one or more candidate sidetrack zones based on identifying cement overlap areas from the hole-casing data. For example, the candidate sidetrack zones may be defined by one or more areas of a single layer of casing cemented to the open wellbore. In some embodiments the sidetrack identification system reduces one or more of the candidate sidetrack zones based on an associated casing having a casing depth above a shallow casing threshold. For example, the sidetrack identification system may reduce one or more of the candidate sidetrack zones to a single point. The single point may be a lowest point in the candidate sidetrack zone.
In some embodiments, the method includes an act of receiving completion data for one or more completion elements. The one or more completion elements may include a production packer.
In some embodiments, the method includes an act of determining a completion depth for each of the one or more completion elements based on the completion data.
In some embodiments, the method includes an act of selecting one or more sidetrack zones by filtering the one or more candidate sidetrack zones based on one or more of the completion depths. In some embodiments, the method includes receiving cementing data. The sidetrack identification system may filter the one or more candidate sidetrack zones based on the cementing data. For example, the sidetrack identification system may determine a cement quality for one or more areas of the wellbore and may filter out one or more candidate sidetrack zones not associated with areas of good cement quality. In some embodiments, the sidetrack identification system filters out one or more candidate sidetrack zones below the completion depth of the production packer. In some embodiments, the sidetrack identification system receives target data and filters the one or more candidate sidetrack zones based on the target data. For example, the sidetrack identification system may determine one or more trajectories to reach a target through one or more of the candidate sidetrack zones. The sidetrack identification system may select a sidetrack trajectory of the one or more sidetrack trajectories based on a cost function for accessing the target. In some embodiments, the method includes causing the selected sidetrack trajectory to be implemented in a downhole drilling operation.
In some embodiments, the sidetrack identification system performs the method for a plurality of underground wellbores in parallel. For example, the method may be performed for at least 50 underground wellbores in parallel. In some embodiments, the sidetrack identification system performs the method in under 1 minute. For example, the method may be performed for a plurality of underground wellbores in parallel in under 1 minute. In some embodiments, the sidetrack identification system performs the method automatically and without user input.
In some embodiments, one or more computer systems may be used to implement the various devices, components, and systems described herein.
The computer system includes a processor. The processor may be a general-purpose single- or multi-chip microprocessor (e.g., an Advanced RISC (Reduced Instruction Set Computer) Machine (ARM)), a special purpose microprocessor (e.g., a digital signal processor (DSP)), a microcontroller, a programmable gate array, etc. The processor may be referred to as a central processing unit (CPU). Although just a single processor is described in the computer system, in an alternative configuration, a combination of processors (e.g., an ARM and DSP) could be used.
The computer system also includes memory in electronic communication with the processor. The memory may include computer-readable storage media and can be any available media that can be accessed by a general purpose or special purpose computer system. Computer-readable media that store computer-executable instructions are non-transitory computer-readable media (device). Computer-readable media that carry computer-executable instructions are transmission media. Thus, by way of example and not limitations, embodiment of the present disclosure can comprise at least two distinctly different kinds of computer-readable media: non-transitory computer-readable media (devices) and transmission media.
Both non-transitory computer-readable media (devices) and transmission media may be used temporarily to store or carry software instructions in the form of computer readable program code that allows performance of embodiments of the present disclosure. Non-transitory computer-readable media may further be used to persistently or permanently store such software instructions. Examples of non-transitory computer-readable storage media include physical memory (e.g., RAM, ROM, EPROM, EEPROM, etc.), optical disk storage (e.g., CD, DVD, HDDVD, Blu-ray, etc.), storage devices (e.g., magnetic disk storage, tape storage, diskette, etc.), flash or other solid-state storage or memory, or any other non-transmission medium which can be used to store program code in the form of computer-executable instructions or data structures and which can be accessed by a general purpose or special purpose computer, whether such program code is stored or in software, hardware, firmware, or combinations thereof.
Instructions and data may be stored in the memory. The instructions may be executable by the processor to implement some or all of the functionality disclosed herein. Executing the instructions may involve the use of the data that is stored in the memory. Any of the various examples of modules and components described herein may be implemented, partially or wholly, as instructions stored in memory and executed by the processor. Any of the various examples of data described herein may be among the data that is stored in memory and used during execution of the instructions by the processor.
A computer system may also include one or more communication interfaces for communicating with other electronic devices. The communication interface(s) may be based on wired communication technology, wireless communication technology, or both. Some examples of communication interfaces include a Universal Serial Bus (USB), an Ethernet adapter, a wireless adapter that operates in accordance with an Institute of Electrical and Electronics Engineers (IEEE) 802.11 wireless communication protocol, a Bluetooth® wireless communication adapter, and an infrared (IR) communication port.
The communication interfaces may connect the computer system to a network. A “network” or “communications network” may generally be defined as one or more data links that enable the transport of electronic data between computer systems and/or modules, engines, and/or other electronic devices. When information is transferred or provided over a communication network or another communications connection (either hardwired, wireless, or a combination of hardwired or wireless) to a computing device, the computing device properly views the connection as a transmission medium. Transmission media can include a communication network and/or data links, carrier waves, wireless signals, and the like, which can be used to carry desired program or template code means or instructions in the form of computer-executable instruction or data structures and which can be accessed by a general purpose or special purpose computer.
A computer system may also include one or more input devices and one or more output devices. Some examples of input devices include a keyboard, mouse, microphone, remote control device, button, joystick, trackball, touchpad, and lightpen. Some examples of output devices include a speaker and a printer. One specific type of output device that is typically included in a computer system is a display device. Display devices used with embodiments disclosed herein may utilize any suitable image projection technology, such as liquid crystal display (LCD), light-emitting diode (LED), gas plasma, electroluminescence, or the like. A display controller may also be provided, for converting data stored in the memory into text, graphics, and/or moving images (as appropriate) shown on the display device. The various components of the computer system may be coupled together by one or more buses, which may include a power bus, a control signal bus, a status signal bus, a data bus, etc.
The techniques described herein may be implemented in hardware, software, firmware, or any combination thereof, unless specifically described as being implemented in a specific manner. Any features described as modules, components, or the like may also be implemented together in an integrated logic device or separately as discrete but interoperable logic devices. If implemented in software, the techniques may be realized at least in part by a non-transitory processor-readable storage medium comprising instructions that, when executed by at least one processor, perform one or more of the methods described herein. The instructions may be organized into routines, programs, objects, components, data structures, etc., which may perform particular tasks and/or implement particular data types, and which may be combined or distributed as desired in various embodiments.
Further, upon reaching various computer system components, program code in the form of computer-executable instructions or data structures can be transferred automatically or manually from transmission media to non-transitory computer-readable storage media (or vice versa). For example, computer executable instructions or data structures received over a network or data link can be buffered in memory (e.g., RAM) within a network interface module (NIC), and then eventually transferred to computer system RAM and/or to less volatile non-transitory computer-readable storage media at a computer system. Thus, it should be understood that non-transitory computer-readable storage media can be included in computer system components that also (or even primarily) utilize transmission media.
The embodiments of the sidetrack identification system have been primarily described with reference to wellbore drilling operations; the sidetrack identification system described herein may be used in applications other than the drilling of a wellbore. In other embodiments, the sidetrack identification system according to the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources. For instance, the sidetrack identification system of the present disclosure may be used in a borehole used for placement of utility lines. Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.
One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous embodiment-specific decisions will be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one embodiment to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.
Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.
A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.
The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.
The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.
This application claims priority to and the benefit of U.S. Provisional Application No. 63/582,978, filed on Sep. 15, 2023, which is hereby incorporated by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 63582978 | Sep 2023 | US |
