SYSTEM AND METHOD FOR CARBONATED WATER INJECTION FOR PRODUCTION SURVEILLANCE AND WELL STIMULATION

Information

  • Patent Application
  • 20240368987
  • Publication Number
    20240368987
  • Date Filed
    April 23, 2024
    10 months ago
  • Date Published
    November 07, 2024
    3 months ago
Abstract
A method involves detecting parameters corresponding to a hydraulic connection between wells in a reservoir. Such method includes injecting carbonated water into a CO2 injection well. The method further includes identifying a presence of the carbonated water around a CO2 recipient well. The method also includes determining at least one parameter corresponding to the hydraulic connection between the CO2 injection well and the CO2 recipient well based on the presence of the carbonated water around the CO2 recipient well.
Description
FIELD OF THE INVENTION

The techniques described herein relate generally to the field of hydrocarbon well completions and hydraulic fracturing operations. More specifically, the techniques described herein relate to determining parameters corresponding to a hydraulic connection between wells using carbonated water injection.


BACKGROUND OF THE INVENTION

This section is intended to introduce various aspects of the art, which may be associated with embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.


Low-permeability hydrocarbon reservoirs are often stimulated using hydraulic fracturing techniques. Hydraulic fracturing consists of injecting a volume of fracturing fluid through created perforations and into the surrounding reservoir at such high pressures and rates that the reservoir rock in proximity to the perforations cracks open and extends outwardly in proportion to the injected fluid volume. This results in the creation of fractures that serve as a conduit for fluid within the reservoir, thus permitting hydrocarbon fluids to flow into the wellbore and then be produced at the surface. In operation, the success of the hydraulic fracturing process has a direct impact on the production characteristics of the hydrocarbon well. Specifically, the geometry, conductivity, dimensions, and/or extent of the hydraulic fractures affects the amount of hydrocarbon fluids that may be recovered from the reservoir.


With this in mind, information about the geometry, conductivity, dimensions, and/or extent of the hydraulic fractures can be used to, for example, guide completion stage and/or well spacing, to mitigate environmental concerns, and/or to improve the accuracy of numeric models of hydrocarbon wells.


Well spacing and stacking decisions are irreversible decisions that impact billions of dollars in aggregate capital expenditure in unconventional reservoir development. In practice, there is a very short influence window from which information obtained from previous wells can be used to improve future wells. As such, there is a compelling need for reliable, low-cost, rapid turn-around time diagnostics to illuminate the relationships among well communication, well performance, and well design (e.g., stimulation, development order, etc.) for all scopes of development, including new-drills, in-fills, and enhanced oil recovery (EOR) projects.


SUMMARY OF THE INVENTION

An embodiment provided herein relates to a method for detecting parameters corresponding to a hydraulic connection between wells in a reservoir. The method includes injecting carbonated water into a CO2 injection well. The method also includes identifying a presence of the carbonated water around a CO2 recipient well. The method further includes determining at least one parameter corresponding to the hydraulic connection between the CO2 injection well and the CO2 recipient well based on the presence of the carbonated water around the CO2 recipient well.


Another embodiment provided herein relates to a well system. The well system includes a pump for injecting carbonated water into a CO2 injection well in order to permit detecting of parameters corresponding to a hydraulic connection between the CO2 injection well and a CO2 recipient well. The well system also includes a detection device that identifies a presence of the carbonated water around the CO2 recipient well. The well system additionally includes a computing device that determines at least one parameter corresponding to the hydraulic connection between the CO2 injection well and the CO2 recipient well based on the presence of the carbonated water around the CO2 recipient well.


A still further embodiment provided herein relates to a method for detecting parameters corresponding to a hydraulic connection between wells in a reservoir. The method includes injecting a substance dissolved in water into an injection well, the substance selected from a group consisting of carbon monoxide, nitrogen, hydrogen or toluene. The method also includes identifying a presence of the substance around a recipient well. The method further includes determining at least one parameter corresponding to the hydraulic connection between the injection well and the recipient well based on the presence of the substance water around the recipient well.


These and other features and attributes of the disclosed embodiments of the present techniques and their advantageous applications and/or uses will be apparent from the detailed description that follows.





BRIEF DESCRIPTION OF THE DRAWINGS

To assist those of ordinary skill in the relevant art in making and using the subject matter described herein, reference is made to the appended drawings, where:



FIG. 1 is a simplified schematic view of a CO2 injection well and a CO2 recipient well that may be utilized in accordance with the present techniques;



FIG. 2 is a schematic view of an exemplary embodiment of the CO2 injection well and the CO2 recipient well of FIG. 1 shown in the context of a reservoir;



FIG. 3 is a schematic illustration showing a plan view of a reservoir including wells and injection zones showing the spread of hydraulic fractures and injected carbonated water therein according to an exemplary embodiment of the present techniques;



FIG. 4 is a process flow diagram of an exemplary method for detecting parameters corresponding to a hydraulic connection between wells using carbonated water injection according to the present techniques;



FIG. 5 is a graph showing the identification of hydraulic communications between wells according to the present techniques;



FIG. 6 is a block diagram of an exemplary cluster computing system that may be utilized to implement at least a portion of the present techniques; and



FIG. 7 is a block diagram of an exemplary non-transitory, computer-readable storage medium that may be used for the storage of data and modules of program instructions for implementing at least a portion of the present techniques.





It should be noted that the figures are merely examples of the present techniques and are not intended to impose limitations on the scope of the present techniques. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the techniques.


DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

In the following detailed description section, the specific examples of the present techniques are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for exemplary purposes only and simply provides a description of the embodiments. Accordingly, the techniques are not limited to the specific embodiments described below, but rather, include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.


At the outset, and for case of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined below, it should be given the broadest definition those skilled in the art have given that term as reflected in at least one printed publication or issued patent. Further, the present techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or techniques that serve the same or a similar purpose are considered to be within the scope of the present claims.


As used herein, the singular forms “a,” “an,” and “the” mean one or more when applied to any embodiment described herein. The use of “a,” “an,” and/or “the” does not limit the meaning to a single feature unless such a limit is specifically stated.


The term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and/or B,” when used in conjunction with open-ended language such as “including,” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.


As used herein, the term “any” means one, some, or all of a specified entity or group of entities, indiscriminately of the quantity.


The phrase “at least one,” when used in reference to a list of one or more entities (or elements), should be understood to mean at least one entity selected from any one or more of the entities in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities, and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently, “at least one of A and/or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B, and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C,” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B, and C together, and optionally any of the above in combination with at least one other entity.


As used herein, the phrase “based on” does not mean “based only on,” unless expressly specified otherwise. In other words, the phrase “based on” means “based only on,” “based at least on,” and/or “based at least in part on.”


As used herein, the terms “example,” exemplary,” and “embodiment,” when used with reference to one or more components, features, structures, or methods according to the present techniques, are intended to convey that the described component, feature, structure, or method is an illustrative, non-exclusive example of components, features, structures, or methods according to the present techniques. Thus, the described component, feature, structure, or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, structures, or methods, including structurally and/or functionally similar and/or equivalent components, features, structures, or methods, are also within the scope of the present techniques.


As used herein, the term “field” (sometimes referred to as an “oil and gas field” or a “hydrocarbon field”) refers to an area including one or more hydrocarbon wells for which hydrocarbon production operations are to be performed to provide for the extraction of hydrocarbon fluids from a corresponding subterranean formation.


The term “fracture” refers to a crack or surface of breakage induced by an applied pressure or stress within a subterranean formation.


As used herein, the term “fluid influx sensor” is used to refer to any suitable type of measurement device that is capable of detecting (either directly or indirectly) the influx of fluid into a wellbore, and the term “fluid influx data” is used to refer to data that are measured using such a fluid influx sensor. As an example, the fluid influx sensor described herein may include (but is not limited to) a pressure transducer, where such pressure transducer may include any type of pressure gauge or other pressure-measuring device that is coupled to the fluid column within a wellbore and is configured to measure pressure data corresponding to the wellbore. As another example, the fluid influx sensor described herein may additionally or alternatively include (but is not limited to) a fiber optic cable that is configured to measure strain data corresponding to the wellbore. As another example, the fluid influx sensor described herein may additionally or alternatively include (but is not limited to) any other suitable type of measurement device that is configured to measure data relating to the dimensions (e.g., the circumference) of the casing within the wellbore and/or data relating to the fluid level inside the wellbore, for example. Generally speaking, the fluid influx data described herein include data that can be used to directly or, more preferably, indirectly determine one or more parameters corresponding to one or more hydraulic connections between multiple hydrocarbon wells, as described herein.


The term “hydraulic fracturing” refers to a process for creating fractures (also referred to as “hydraulic fractures”) that extend from a wellbore into a reservoir, so as to stimulate the flow of hydrocarbon fluids from the reservoir into the wellbore. A fracturing fluid is generally injected into the reservoir with sufficient pressure to create and extend multiple fractures within the reservoir, and a proppant material is used to “prop” or hold open the fractures after the hydraulic pressure used to generate the fractures has been released.


As used herein, the term “surface” refers to the uppermost land surface of a land well, or the mud line of an offshore well, while the term “subsurface” (or “subterranean”) generally refers to a geologic strata occurring below the earth's surface. Moreover, as used herein, “surface” and “subsurface” are relative terms. The fact that a particular piece of equipment is described as being on the surface does not necessarily mean it must be physically above the surface of the earth but, rather, describes only the relative placement of the surface and subsurface pieces of equipment. In that sense, the term “surface” may generally refer to any equipment that is located above the casing strings and other equipment that is located inside the wellbore. Moreover, according to embodiments described herein, the terms “downhole” and “subsurface” are sometimes used interchangeably, although the term “downhole” is generally used to refer specifically to the inside of the wellbore.


The term “wellbore” refers to a borehole drilled into a subterranean formation. The borehole may include vertical, deviated, highly deviated, and/or horizontal sections. The term “wellbore” also includes the downhole equipment associated with the borehole, such as the casing strings, production tubing, gas lift valves, and other subsurface equipment. Relatedly, the term “hydrocarbon well” (or simply “well”) includes the wellbore in addition to the wellhead and other associated surface equipment.


According to the present technological advancement, carbonated water (a relatively homogeneous mixture of CO2 dissolved in water) injection may be used as a relatively inexpensive diagnostic test to identify connections between wells within a hydrocarbon reservoir. In an exemplary embodiment of the present techniques, carbonated water may be continuously mixed from frac water and CO2 at the surface prior to injection in order to achieve a relatively uniform composition. As an alternative, a slug of liquid CO2 (preferably kept cold) could be injected into a CO2 injection well and chased with water to mix downhole.


Analysis using CO2 injection may be used in an early phase of development of a reservoir when additional wells are being planned to improve the output of the reservoir. Up-front costs of analysis using CO2 injection may be defrayed through CO2 sequestration (dispersing carbon into the ground instead of releasing it into the atmosphere), EOR, and the intrinsic value of information conferred by the CO2 injection diagnostic on well communication versus time. Moreover, information about the geometry, conductivity, dimensions, and/or extent of the hydraulic fractures can be used to, for example, guide completion stage and/or well spacing, to mitigate environmental concerns, and/or to improve the accuracy of numeric models of hydrocarbon wells.


The inter-well parameter detection techniques of CO2 injection described herein provide for the detection of various parameters corresponding to a CO2 injection well that is in hydraulic communication with another well referred to herein as a CO2 recipient well. More specifically, the present techniques leverage fluid influx data measured via open perforations within the CO2 recipient well to detect various parameters corresponding to a hydraulic connection between the CO2 injection well and the CO2 recipient well, where such hydraulic connection is formed via hydraulic fractures initiated previously within the reservoir.


For example, the fluid influx data obtained from the CO2 recipient well may be leveraged to detect the extent of hydraulic fracturing within the reservoir, to characterize the growth of the hydraulic fractures, to determine the azimuth of the hydraulic fractures, to detect the total (or approximate) number of hydraulic fractures that have arrived at the CO2 recipient well, to determine the conductivities of the hydraulic fractures, to determine the total (or approximate) number of hydraulic connections between the CO2 injection well and the CO2 recipient well, to determine the intensity of the hydraulic connection(s) between the CO2 injection well and the CO2 recipient well, and/or to determine the degree of isolation integrity in the CO2 recipient well.


According to the inter-well parameter detection techniques described herein, the CO2 injection well and the CO2 recipient well are located in the same field or in adjacent fields. Moreover, the CO2 injection well and the CO2 recipient well are configured such that one or more hydraulic fractures initiated within a particular stage of the treatment well are capable of establishing one or more hydraulic connections via propagation of the hydraulic fracture(s) through the subsurface region in the field. In various embodiments, such hydraulic connections are provided through hydraulic communication between the perforations (and corresponding hydraulic fractures).


Moreover, in some embodiments, the configuration of the CO2 injection well and the CO2 recipient well(s) is specifically controlled to enable efficient implementation of the present techniques. In such embodiments, this may include drilling the CO2 injection wellbore and the CO2 recipient wellbore such that the wellbores follow approximately the same path within the subsurface region, while being vertically and/or horizontally separated from each other by some predetermined offset.


The present techniques of discovery of hydraulic connections may be applied to a wide range of well types, including injection of fluid into vertical wells that may be producing, converted monitor wells, or dedicated monitor wells, to name a few examples. Further, the present techniques may be used to inject fluid into a horizontal well for monitoring a vertical well, such as a producer well, a converted monitor well, or a dedicated monitor well.


In addition, in some such embodiments, the perforations within each stage (or at least a portion of the stages) may approximately line up with each other (or may be offset by some predetermined amount or within some predetermined range). Furthermore, in some such embodiments, the present techniques may include setting up clusters of perforations of variable lengths, skipping portions of the wellbore(s), or even drilling dedicated wells to specifications. However, it should also be noted that the present techniques can be performed without any pre-planning regarding the configuration of the CO2 injection well and the CO2 recipient well. In general, the present techniques can be applied for any multi-well configuration in which one or more hydraulic fractures are capable of propagating within the field.


In some embodiments, the CO2 injection well described herein has not been previously hydraulically fractured. For example, the CO2 injection well may be entirely (or partially) perforated but not yet hydraulically fractured. In other embodiments, the CO2 injection well has been hydraulically fractured for one or more previous stages, but not for the stage that is being monitored. In yet other embodiments, the entire CO2 injection well (or some substantial portion thereof) has already undergone a hydraulic fracturing operation.


In various embodiments, hydraulic fracture(s) are first initiated at the CO2 injection well, and such hydraulic fracture(s) are used to establish hydraulic communication between the CO2 injection well and the CO2 recipient well (i.e., by providing one or more hydraulic connections between the two wells). One or more fluid influx sensors (which may be located downhole and/or at the surface) are then used to measure the response in the CO2 recipient well, and the measured fluid influx data are used to determine one or more parameters relating to the hydraulic connection(s) between the two wells, such as, for example, the arrival of the hydraulic fractures at the CO2 recipient well. Examples of additional parameters that may be determined using such fluid influx data include the fracture growth patterns within the subsurface region, the number of hydraulic fractures, the number of hydraulic connections between the wellbores, the azimuth of one or more of the hydraulic fractures, the intensity of the hydraulic connection(s) between the CO2 injection well and the CO2 recipient well, the conductivity of one or more of the hydraulic fractures, and/or the degree of isolation integrity in the CO2 recipient well. Moreover, in some embodiments, the fluid influx data may be used to derive interpretations regarding changes in the created fracture system over time, including changes in the fracture growth patterns, the well connectivity, and/or other early insights or indicators regarding future production potential. In some embodiments, the present techniques may enable the fluid influx data to be coupled with a hydraulic fracture model to provide more detailed information regarding the subsurface region. Furthermore, in some embodiments, the fluid influx data may be used to determine information relating to post-shut-in fracture patterns and trends, including the continuity and/or conductivity of the hydraulic connection(s) between the wellbores subsequent to shut-in.


The present techniques may be employed to elucidate additional reservoir dynamic behavior. For example, the present techniques may be employed to determine diffusive mass-transfer of CO2 between and among fluid phases in the fracture, near-fracture region, and matrix. Other uses include the calibration of reservoir simulation, including numerical discretization of the subsurface and fluid property description/characterization. Still another use includes determining solubility and partitioning of CO2 into various phases (brine, oil, and gases). Moreover, the present techniques may be employed to provide knowledge concerning CO2-brine system fluid properties at reservoir conditions.


The inter-well parameter detection techniques described herein can be advantageously applied to any subsurface hydraulic fracturing scenarios involving multiple wells that are within relatively close proximity to each other. Additionally, such techniques advantageously utilize sensor data that are often measured for wells and, thus, generally do not require additional measurements with respect to the CO2 recipient well beyond those that are routinely captured.


Turning now to the figures, FIGS. 1 and 2 provide examples of wells that may be utilized to perform the techniques described herein. Within such figures, elements that serve a similar (or at least substantially similar) purpose may be labeled with like numbers. Moreover, those skilled in the art will appreciate that the schematic views of FIGS. 1 and 2 are not intended to indicate that the well(s) described herein are to include all of the components shown in the figures in every embodiment, or that the well(s) are limited to only such components. Rather, any number of components may be added to, or omitted from, the well(s) without departing from the scope of the present techniques.



FIG. 1 is a simplified schematic view of a CO2 injection well and a CO2 recipient well that may be utilized in accordance with the present techniques, while FIG. 2 is a schematic view of an exemplary embodiment of the CO2 injection well and the CO2 recipient well of FIG. 1 shown in the context of a reservoir. In other words, FIG. 2 is a more detailed illustration of examples of components/structures that may be included in the wells shown in FIG. 1.


Turning first to FIG. 1, a CO2 injection well 100 and a CO2 recipient well 102 are provided. In various embodiments, the CO2 injection well 100 is a producer well or any other suitable type of hydrocarbon well that is configured to undergo a hydraulic fracturing process. Moreover, in various embodiments, the CO2 recipient well 102 may be a separate producer well, a dedicated CO2 recipient well, or any other suitable type of well that is offset from the CO2 injection well 100 and is configured to measure fluid influx data according to the present techniques. As described above, according to embodiments described herein, the CO2 recipient well 102 may be a well that has not yet undergone a hydraulic fracturing process.


CO2 is present in low (but known) baseline concentrations in most unconventional reservoirs. Therefore, monitoring for the presence of CO2 (above baseline) in the production stream of a well will unambiguously demonstrate (1) communication between wells or (2) fluid production from stages receiving the carbonated water. Specifically, when carbonated water is injected into the CO2 injection well 100 during the hydraulic fracturing process, as indicated by arrow 104, the carbonated water flows through perforations 106 within the corresponding stage of the CO2 injection well 100, and into one or more hydraulic fractures 108. As shown in FIG. 1, at least a portion of such hydraulic fractures 108 provide one or more hydraulic connections between the CO2 injection well 100 and the CO2 recipient well 102, thus establishing hydraulic communication between the two wells. Specifically, in various embodiments, such hydraulic fractures 108 establish hydraulic connections between the perforations within the particular stage of the CO2 injection well 100 and the perforations 110 within the corresponding stage of the CO2 recipient well 102. Moreover, in various embodiments, the initiation of such hydraulic connections enables carbonated water to travel through the fluid column within the wellbore of the CO2 recipient well 102, as indicated by arrow 112, and to be measured via a measuring device 114 that is coupled to the fluid column within the wellbore of the CO2 recipient well 102.


Examples of types of measuring devices that may be used in connection with the present techniques include multi-phase flow meters and indirect measuring devices that track properties like density, acoustic velocity, optical properties. Other examples of measuring devices include a pH meter to measure the real time pH of produced water. A lower pH level in water could imply a greater presence of CO2. Further examples of measuring devices that could be used include corrosion rings that may be placed in the casing, wellhead tree, or flowline. Corrosion rings could reflect the relative abundance of CO2. CO2 levels could be detected in gas from the CO2 recipient well. Gas samples could be collected at the surface.


Those skilled in the art will appreciate that, while such measuring device 114 is depicted in FIG. 1 as being at or near the surface or wellhead of the CO2 recipient well 102, the measuring device 114 may additionally or alternatively be positioned anywhere within the wellbore itself, including within proximity to the stage of interest. Furthermore, in some embodiments, multiple measuring devices 114 (e.g., potentially one or more arrays of measuring devices 114) may be used. Furthermore, it should be noted that, while a measuring device is utilized as the fluid influx sensor in the exemplary embodiment shown in FIG. 1, other types of fluid influx sensors may additionally or alternatively be utilized, depending on the details of the particular embodiment. For example, in some embodiments, the fluid influx sensor(s) may include one or more fiber optic cables that are configured to measured strain data corresponding to the wellbore of the CO2 recipient well 102. Fiber optic cables could be configured for DAS/DTS (distributed acoustic sensing/distributed temperature sensing) to infer fluid movement and composition. In addition, multiphase flow meters and production logging test (PLT) devices could be used. Strain data may provide additional diagnostic detail to identify the presence/dynamic response of fractures.


According to the embodiment shown in FIG. 1, the data recorded by the measuring device 114 (and/or other type(s) of fluid influx sensor(s)) are used to determine one or more parameters corresponding the hydraulic connection(s) between the two wells 100 and 102. Such parameters may include (but are not limited to) the arrival of carbonated water at the CO2 recipient well 102 (including the relative volume of CO2 received), the fracture growth patterns within the subsurface region, the total (or approximate) number of hydraulic fractures 108, the total (or approximate) number of hydraulic connections between the wells 100 and 102, the azimuths of the hydraulic fractures 108, the intensities of the hydraulic connections between the wells 100 and 102, the conductivities of the hydraulic fractures 108, and/or the degree of isolation integrity in the CO2 recipient well 102.


In some embodiments, carbonated water content (and/or other type(s) of fluid influx data) may be used to derive interpretations regarding changes in the created fracture system over time, including changes in the fracture growth patterns, the well connectivity, and/or other early insights or indicators regarding production operations. In some embodiments, the fluid influx data are also coupled with a hydraulic fracture model to provide more detailed information regarding the subsurface region. Furthermore, in some embodiments, the fluid influx data are used to determine information relating to post-shut-in fracture patterns and trends, including the post-shut-in continuity and/or conductivity of the hydraulic connection(s) between the wells 100 and 102.


Turning now to FIG. 2, the CO2 injection well 100 and the CO2 recipient well 102 each define a corresponding wellbore 200 that extends from a surface 202 into a formation 204 within the subsurface. The formation 204 may include several subsurface intervals, such as a hydrocarbon-bearing interval that is referred to herein as a reservoir 206. In some embodiments, the reservoir 206 is an unconventional, tight reservoir, meaning that it has regions of low permeability. For example, the reservoir 206 may include tight sandstone, tight carbonate, shale gas, coal bed methane, tight oil, and/or tight limestone.


Each wellbore 200 is completed by setting a series of tubulars into the formation 204. These tubulars include several strings of casing, such as a surface casing string 208, an intermediate casing string 210, and a production casing string 212, which is sometimes referred to as a “production liner.” In some embodiments, additional intermediate casing strings (not shown) are also included to provide support for the walls of the wellbore 200. According to the embodiment shown in FIG. 2, the surface casing string 208 and the intermediate casing string 210 are hung from the surface 202, while the production casing string 212 is hung from the bottom of the intermediate casing string 210 using a liner hanger 214.


The surface casing string 208 and the intermediate casing string 210 are set in place using cement 216. The cement 216 isolates the intervals of the formation 204 from the wellbore 200 and each other. The production casing string 212 may also be set in place using cement 216, as shown in FIG. 2. Alternatively, the wellbore 200 may be set as an open-hole completion, meaning that the production casing string 212 is not set in place using cement.


The exemplary wellbores 200 shown in FIG. 2 are both completed horizontally (or laterally). A lateral section of each wellbore 200 is shown at 218. Each lateral section 218 has a heel 220 and a toc 222 that extends through the reservoir 206 within the formation 204.


In various embodiments, because the reservoir 206 is an unconventional, tight reservoir, a hydraulic fracturing process is performed to allow hydrocarbon fluids to be economically produced from the reservoir 206. As shown in FIG. 2, the hydraulic fracturing process may utilize an extensive amount of equipment at a well site 224 located at the surface 202. The equipment may include fluid storage tanks 226 to hold fracturing fluid, such as slickwater, and blenders 228 to blend the fracturing fluid with other materials, such as proppant 230 and other chemical additives, forming a low-pressure slurry. The low-pressure slurry 232 may be run through a treater manifold 234, which may use pumps 236 to adjust flow rates, pressures, and the like, creating a high-pressure slurry 238. According to embodiments described herein, the high-pressure slurry 238 may be pumped down the wellbore 200 of the CO2 injection well 100 via a corresponding wellhead 240 and used to fracture the rocks in the reservoir 206. Moreover, a mobile command center 242 may be used to control the hydraulic fracturing process, as well as the inter-well parameter detection techniques described herein.


Each wellhead 240 may include any arrangement of pipes and valves for controlling the corresponding well 100 or 102. In some embodiments, the wellhead 240 is a so-called “Christmas tree.” A Christmas tree is typically used when the subsurface formation 204 has enough in-situ pressure to drive hydrocarbon fluids from the reservoir 206, up the corresponding wellbore 200, and to the surface 202. The illustrative wellhead 240 includes a top valve 244 and a bottom valve 246. In some contexts, these valves are referred to as “master valves.” Moreover, in various embodiments, the wellhead 240 also couples the corresponding hydrocarbon well 100 or 102 to other equipment, such as equipment for running a wireline (not shown) into the corresponding wellbore 200. In some embodiments, the equipment for running the wireline into the wellbore 200 includes a lubricator (not shown), which may extend as much as 75 feet above the wellhead 240. In this respect, the lubricator must be of a length greater than the length of a bottomhole assembly (BHA) (not shown) attached to the wireline to ensure that the BHA may be safely deployed into the wellbore 200 and then removed from the wellbore 200 under pressure.


While there are several different methods for hydraulically fracturing the reservoir 206 via the CO2 injection well 100 according to embodiments described herein, a hydraulic fracturing process referred to as a “plug-and-perforation process” is described with respect to FIG. 2. During the plug-and-perforation process, a specialized BHA, referred to as a “plug-and-perf assembly,” (not shown) is run into the wellbore 200 of the CO2 injection well 100 via the wireline connected to the corresponding wellhead 240. The wireline provides electrical signals to the surface 202 for depth control. In addition, the wireline provides electrical signals to perforating guns (not shown) included within the plug-and-perf assembly. The electrical signals may allow the operator within the mobile command center 242 to cause the charges within the perforating gun to fire, or detonate, at a desired stage or depth within the wellbore 200.


In operation, the perforating gun is run into the first stage 248 of the CO2 injection well 100, which is located near the toc 222 of the lateral section 218. The perforating gun is then detonated to create a first perforation cluster 250A through the production casing string 212 and the surrounding cement 216. In operation, the perforating gun typically forms one perforation cluster by shooting 12 to 18 perforations at one time, over a 1- to 3-foot region, with each perforation being approximately 0.3 to 0.5 inches in diameter. The perforating gun is then typically moved uphole 10 to 100 feet, and a second perforating gun is used to form a second perforation cluster 250B. This process of forming perforation clusters is repeated another 1 to 18 times to create multiple perforation clusters within a single stage. Therefore, while only five perforation clusters 250A, 250B, 250C, 250D, and 250E are depicted for the first stage 248 of the CO2 injection well 100, each stage of the CO2 injection well 100 may include a total of around 3 to 20 perforation clusters, with each perforation cluster being spaced around 10 to 100 feet apart, for example.


Furthermore, according to embodiments described herein, a similar process may be used to create perforation clusters 252A, 252B, 252C, 252D, and 252E within a corresponding stage 254 of the CO2 recipient well 102. In some embodiments, the perforation clusters 252A-E within the wellbore 200 of the CO2 recipient well 102 are designed to approximately align with the perforation clusters within the wellbore 200 of the CO2 injection well 100. For example, the perforation clusters may be designed to be offset to a certain extent or to be within a certain amount of distance from each other. However, in other embodiments, the techniques described herein are performed without pre-designing or altering the CO2 injection well 100 or the CO2 recipient well 102 to include perforation clusters that align (or approximately align).


In various embodiments, once the perforation clusters 250A, 250B, 250C, 250D, and 250E are formed within the first stage of the CO2 injection well 100, the plug-and-perf assembly is removed from the wellbore 200, and the high-pressure slurry 238 of fracturing fluid is pumped down the wellbore 200, through the perforations within the perforation clusters 250A-E, and into the surrounding reservoir 206, forming corresponding sets of fractures 256A, 256B, 256C, 256D, and 256E within the reservoir 206.


According to embodiments described herein, as such hydraulic fractures 256A-E are formed, at least a portion of the fractures reach or extend to the perforation clusters 252A-E corresponding to the CO2 recipient well 102 (and/or to one or more open ports, sleeves, and/or slots corresponding to the CO2 recipient well 102). As a result, such hydraulic fractures 256A-E establish hydraulic connections between the perforation clusters 250A-E and 252A-E of the two wells 100 and 102, respectively. As described herein, such hydraulic connections provide a means of hydraulic communication between the two wells 100 and 102, thus enabling one or more fluid influx sensors 258 (e.g., a carbonated water measuring device according to the exemplary embodiment shown in FIG. 2) at the CO2 recipient well 102 to measure data regarding carbonated water corresponding to the formation of such hydraulic fractures 256A-E. Such data are then used to determine parameters relating to the hydraulic connection(s) between the wells 100 and 102, including parameters relating to the hydraulic fractures 256A-E originating from the CO2 injection well 100, as described herein.


According to the embodiment shown in FIG. 2, the fluid influx sensor 258 (e.g., the pressure transducer) is coupled to the fluid column within the wellbore 200 of the CO2 recipient well 102 via direct connection with the wellhead 240. However, one or more fluid influx sensors 258 (or one or more arrays of fluid influx sensors 258) may be connected to the wellbore 200 in any suitable manner and/or may be positioned at any number of different locations, including inside the wellbore 200 and/or at the surface 202, depending on the details of the particular implementation.


Those skilled in the art will appreciate that this inter-well parameter detection process may be performed for each stage of the CO2 injection well 100 (or for any subset thereof) and may be used to guide or optimize the hydraulic fracturing operations and/or the overarching hydrocarbon production operations. For example, the detected parameters that are output from the process may be used to generate a well spacing plan that is tailored to the field of interest (i.e., the formation 204 within the subsurface region of interest), and the well spacing plan may then be physically implemented in the field (i.e., by drilling (or causing the drilling of) multiple wells within the field according to such well spacing plan).



FIG. 3 is a schematic illustration showing a plan view of a reservoir 206 including wells and injection zones showing the spread of hydraulic fractures and injected carbonated water therein according to an exemplary embodiment of the present techniques. The present technological innovation exploits the knowledge that CO2 will dissolve in all phases present in the reservoir. Specifically, CO2 will dissolve into oil, water and/or gas, if present. Thus, CO2 may be used as a three-phase tracer because it will mix with water, oil and gas. By uniformly mixing CO2 within the injected water phase, the CO2 will be well dispersed within the fracture network, from which it is free to diffuse into any oil, gas, or background formation water it encounters. This ability to dissolve into all three phases is a strong advantage over other tracers which are specific only to water or oil.


The uniform distribution and ability to partition into all three phases provides a potentially permanent diagnostic tracer (flowback, production, and possibly late-production life). Gas composition is already required for pipeline sales specifications, so the regular sampling for CO2 composition is not burdensome compared with radioactive tracers.


C13 isotopes could be prepared and included in injected carbonated water as an identifying agent to achieve two goals. First, C13 isotopes could be identified to differentiate between native CO2 versus CO2 that is injected to a well according to the present techniques. Second, C13 isotopes could provide rapid identification of the presence of the injected diagnostic CO2 using C13 Nuclear Magnetic Resonance (NMR) or using downhole logging techniques based on radiometric contrast. Well-side gas chromatography (GC) using a total conductivity detector is one additional technique for collecting CO2 abundance data in addition to traditional lab-based analysis of fluid samples collected from the well and/or associated fluid handling equipment. Further, the pH of water received at the CO2 recipient well 102 could be used to identify the presence of CO2 from the CO2 injection well 100.


If multiple CO2 injection wells are being used, different isotopes could be mixed as identifying agents with the carbonated water injected into each of the CO2 injection wells. The use of different isotopes would allow identification of a quantity of carbonated water received from each of the CO2 injection wells at a particular CO2 recipient well. This could allow improved determination of hydraulic connections between wells in the reservoir 206.



FIG. 3 depicts a reservoir 206 that encompasses multiple benches. The benches include a first bench 300, a second bench 302, a third bench 304 and a fourth bench 306. Each of the benches has a plurality of wells, and each of the wells could be used as a CO2 injection well or a CO2 recipient well, as described herein.



FIG. 3 shows a CO2 injection well 100 and a plurality of CO2 recipient wells 102A, 102B and 102C. The CO2 injection well 100 in FIG. 3 is shown in the third bench 304. The CO2 recipient wells 102A and 102C are located in the third bench 304. The CO2 recipient well 102B is in the fourth bench 306.


Fracture zones are shown for some of the wells. The fracture zones show areas in which hydraulic fracturing has been performed. A first fracture zone 308 shows the extent of hydraulic fracturing around the CO2 injection well 100. A second fracture zone 310, a third fracture zone 312 and a fourth fracture zone 314 show the extent of hydraulic fracturing around the CO2 recipient wells 102A, 102B and 102C respectively.


Interactions between the fracture zones could result in hydraulic communication between wells, as evidenced by the fracture zones shown in FIG. 3. These hydraulic connections may be detected through the injection of carbonated water according to the present techniques. Moreover, hydraulic communications could exist between any of the wells in a given reservoir for a variety of reasons. These hydraulic communications may be identified by the carbonated water injection techniques described herein.


The extent of overlap of the fracture zones shown in FIG. 3 are illustrative of the potential hydraulic connections between the CO2 injection well 100 and the CO2 recipient wells 102A, 102B and 102C. For example, there is a relatively large overlap between the first fracture zone 308 (CO2 injection well 100) and the second fracture zone 310 (CO2 recipient well 102A). This relatively large overlap could indicate the existence of a strong hydraulic connection between the CO2 injection well 100 and the CO2 recipient well 102a. Such a connection could persist for a relatively long time.


As shown in FIG. 3, there is a moderate overlap between the first fracture zone 308 (CO2 injection well 100) and the fourth fracture zone 314 (CO2 recipient well 102C). The presence of this moderate overlap could be indicative of a moderate hydraulic connection between the CO2 injection well 100 and the CO2 recipient well 102C. Such a connection may persist for a moderately long time.


There is a relatively small overlap between the first fracture zone 308 (CO2 injection well 100) and the third fracture zone 312 (CO2 recipient well 102B). Similarly, there is a relatively small overlap between the fourth fracture zone 314 (CO2 recipient well 102C) and the third fracture zone 312 (CO2 recipient well 102B). These relatively small overlaps could be indicative of a relatively small hydraulic connections between the CO2 injection well 100 and CO2 recipient well 102B, as well as between CO2 recipient wells 102B and 102C. Such relatively small connections could persist for a relatively short period of time before disappearing.



FIG. 4 is a process flow diagram of an exemplary method 500 for detecting parameters corresponding to a hydraulic connection between wells using carbonated water injection according to the present techniques. The method 400 may be executed, at least in part, by one or more computing systems including one or more processors, such as the cluster computing system described with respect to FIG. 6, or any suitable variation(s) thereof. In some embodiments, such computing system(s) (or a portion of such computing systems) may be located at the mobile command center 242 described with respect to FIG. 2, which may form part of the same hydrocarbon field as the CO2 injection well 100 and the CO2 recipient well 102 described herein.


The method 400 begins at block 402, at which carbonated water is injected into a CO2 injection well. As described herein, the carbonated water will flow in the formation 204 via hydraulic fractures, as shown by the fracture zones 308, 310, 312 and 314 shown in FIG. 3, and other permeable features originating naturally, anthropogenically induced, of a composite nature, or of unknown provenance nature facilitating subsurface movement of carbonated water.


At block 404, presence of carbonated water injected into the CO2 injection well 100 is detected at one or more CO2 recipient wells, such as the CO2 recipient wells 102A, 102B and 102C shown in FIG. 3. As noted herein, the carbonated water may be identified and CO2 therein detected using any method known to those of skill in the art. The use of isotopes may allow identification of CO2 from a plurality of CO2 injection wells.


Moreover, in various embodiments, fluid influx data including the presence of CO2 may be measured repeatedly or continuously. In some embodiments, fluid influx data may be measured using pressure transducers, temperature transducers, acoustic, optical, mechanical, and logging arrays (PLT or fiber optic). In other embodiments, equipment to detect the presence of CO2 may include direct analysis of fluid samples (gas chromatography, pH, alkalinity, measurement of relative increased corrosion using corrosion rings, etc).


At block 406, at least one parameter corresponding to the hydraulic connection between the CO2 injection well 100 and one or more CO2 recipient wells 102A, 102B and 102C is identified. The identification of the parameter may be based on the presence of the carbonated water around the CO2 recipient well.


Hydraulic connection data may be used to determine the fracture growth pattern of one or more of the hydraulic fractures, the number of hydraulic fractures that have arrived at the CO2 recipient well, the number of hydraulic connections between the CO2 injection well and the CO2 recipient well, the azimuth of one or more of the hydraulic fractures, and/or the conductivity of one or more of the hydraulic fractures. Additionally or alternatively, in some embodiments, this includes determining the intensity of the hydraulic connection(s) between the CO2 injection well and the CO2 recipient well, and/or the degree of isolation integrity in the CO2 recipient well. Additionally or alternatively, in some embodiments, this includes determining changes in at least a portion of the hydraulic fractures over time using the measured CO2 data. Additionally or alternatively, in some embodiments, this includes determining the post-shut-in continuity and/or the post-shut-in conductivity of the hydraulic connection(s) between the CO2 injection well and the CO2 recipient well. Moreover, in some embodiments, the method 400 also includes coupling the measured fluid influx data to a hydraulic fracture model that represents the fracture system corresponding to the hydraulic fractures.


Those skilled in the art will appreciate that the exemplary method 400 of FIG. 4 is susceptible to modification without altering the technical effect provided by the present techniques. In practice, the exact manner in which the method is implemented will depend, at least in part, on the details of the specific implementation. For example, in some embodiments, some of the blocks shown in FIG. 4 may be altered or omitted from the method 400 and/or new blocks may be added to the method 400. Moreover, in some embodiments, the method 400 is performed for multiple CO2 recipient wells that are located in the same field as the CO2 injection well and/or in one or more adjacent fields.


Furthermore, in various embodiments, the hydraulic connection(s) are provided between perforations within the stage of the CO2 injection well and perforations within a corresponding stage of the CO2 recipient well. In such embodiments, the method 400 may include configuring the CO2 injection well and the CO2 recipient well such that the perforations within the stage of the CO2 injection well and the perforations within the corresponding stage of the CO2 recipient well are offset by less than or equal to a predetermined distance in at least one direction.


In various embodiments, the method 400 further includes utilizing the detected parameters to generate a well spacing plan that is customized to the particular field. In such embodiments, the method 400 may further include executing the well spacing plan by drilling (or causing the drilling of) multiple wells within the field according to the specifications of the well spacing plan. Additionally or alternatively, the method 400 may include performing hydraulic fracturing operations and/or the overarching hydrocarbon production operations for the field in accordance with the detected parameters. This may include, for example, utilizing the detected parameters (including the data regarding hydraulic fracture arrival) to modify the hydraulic fracturing operations and/or the hydrocarbon production operations in any other suitable manner.



FIG. 5 is a graph 500 showing the identification of hydraulic communications between wells according to the present techniques. The graph 500 has an x-axis 502 representing time. A y-axis 504 represents an amount of CO2 in a produced stream, such as from a CO2 recipient well following injection of carbonated water into a neighboring CO2 injection well.


In accordance with the present technological innovation, shortly after injection of carbonated water into the CO2 injection well, the carbonated water itself may be detected at CO2 recipient wells. However, at longer timescales, oil and gas containing the injected CO2 may be identified. The diagnostic process using injected carbonated water is readily paired with other techniques like time lapse geochemistry by way of example and not limitation.


Various traces are shown on the graph 500. The traces are representative of parameters that may identify hydraulic connections identified by carbonated water injection, as described herein.


A wetted fracture hit trace 506 defines a condition that could potentially represent a hydraulic connection known as a wetted frac hit, as detected by the presence of CO2. A wetted fracture hit generally denotes the establishment of communication between two or more wells via a single hydraulic fracture (or plurality of fractures) wherein the fracture (or plurality of fractures) does not sustain high levels of communication between the well(s) due to insufficient placement of proppant (and/or presence of self-propping asperities). The term “wetted fracture hit” is a relatively subjective term, but the diagnostic distinction between wetted fracture hits and propped fracture hits is that of “relatively sustained” conductivity through time and/or during depletion or injection.


The wetted fracture hit trace 506 shows identification of a relatively small amount of CO2 at a CO2 recipient well 102. Further, the wetted fracture hit trace 506 shows the level of measured CO2 decreasing rather quickly.


A long term conductive fracture trace 508 defines a condition that could potentially represent a hydraulic connection known as a long term conductive fracture. A long term conductive fracture occurs with a fracture (or plurality of fractures) originating at one well connects with a fracture originating at a different well. Proppant flows into the fracture region (or self-propping asperities are created) to maintain the conductivity of the fracture system. The long term conductive fracture trace 508 shows that an amount of detected CO2 at the CO2 recipient well 102 is initially at a relatively high level and reduces somewhat over time.


A CO2 frac well trace 510 defines a condition that could potentially represent a hydraulic connection known as a CO2 frac well. The CO2 frac well condition means that the fracture network of the CO2 injection well 100 has interacted with the fracture network of the CO2 recipient well 102. The CO2 frac well trace 510 shows an initially high level of detected CO2 at the CO2 recipient well 102, and maintaining of a relatively high level of CO2 over a relatively long period of time.


A re-frac trace 512 shows a hydraulic connection that is not initially present between the CO2 injection well 100 and the CO2 recipient well 102. This is seen at the initial time of the graph 500. At a later time, indicated by the dashed line 514 a refracking operation is performed at a well in the reservoir 206. In an exemplary embodiment, the refracking operation is performed at the CO2 injection well 100. Alternatively, the refracking operation could be performed at any well within the reservoir 206. After the refracking operation is performed, a hydraulic connection develops between the well on which the refracking operation was performed and the CO2 recipient well (at which the level of CO2 is being measured and recorded by the re-frac trace 512). This is evidenced by the measurement of a CO2 peak 516, indicating the presence of CO2 at the CO2 recipient well. As shown by the re-frac trace 512, the level of CO2 measured at the CO2 recipient well decreases over a relatively short period of time.


The present technological innovation provides a number of benefits in terms of identifying and predicting the behavior of hydraulic connections within the reservoir 206. For example, injection of carbonated water into the CO2 injection well 100 would potentially not require the obtaining of separate permits or other environmental approvals. This could provide a competitive advantage relative to the injection of pure CO2 into a well.


As another advantage, the CO2 dissolved into water would dissolve into all phases present in the reservoir 206 (e.g., oil, water and gas, if present). This would provide a more permanent diagnostic tool compared to short-lived radioactive tracers and/or tracers only suitable for oil, water or the tagging of proppant.


Dissolved CO2 may also provide a built-in solution gas drive to enhance water flowback following stimulation. The swelling of the adjacent oleic phase also provides an additional frac clean-up mechanism and may improve overall oil recovery.


Embodiments of the present technological innovation may provide relatively inexpensive diagnostic testing with potential value addition via CO2 sequestration (contingent on value of CO2 credits and project costs). Another use case of CO2 injection and adjacent measurement could be to evaluate unconventional reservoirs for CO2 sequestration potential. This could be valuable in candidate selection for huff and puff operations or carbon sequestration.


As another benefit, the diagnostic information supplied via CO2 injection and surveillance described herein could result in improved understanding of fracture geometry (for example, wetted versus conductive, areal versus vertical extent). Improved understanding could also be obtained regarding the creation of new fractures in re-fracs, infill drilling, or so called “huff and puff” operations. Huff and puff operations is an industry shorthand term that describes a process of EOR in which a solvent/gas is injected into a wellbore to increase the pressure and facilitate production of hydrocarbons. The process is typically repeated a number of times and is distinguishable from conventional gas flooding with dedicated injection and production wells.


Those of skill in the art will appreciate that, if CO2 injection provides measurable uplift in hydrocarbon production, total well count could be reduced. Reduction in the well count could desirably lead to reduced water utilization, disposal volumes, and capital requirements during depletion. Embodiments of the present techniques may provide the benefits of improved oil recovery, reduced water usage, and CO2 sequestration, to align with a net zero strategy.


There are a number of exemplary applications for the present technological innovation. For example, carbonated water may be injected for purposes performing a fracking operation. Carbonated frack water may be injected into an interior well of a cube for primary production and monitoring for CO2 production in offset neighbor wells. CO2 sequestration and EOR are potential benefits. However, a primary goal of the present techniques is to identify hydraulic fluid communication between wells.


Another potential application of the present technological innovation is injecting a carbonated water slug into a depleted well(s) where the communication across benches is an unknown when screening for zonal isolation for a huff and puff operation in a different zone. By injecting the slug of carbonated water into depleted wells, conformance control and communication diagnostics may be simultaneously achieved.


Carbonated water could potentially be injected into every other frack stage to cut down the amount of CO2 needed and to dilute the amount of CO2 in the produced gas stream. This would serve to dilute the CO2 present using sweet gas from non-treated stages.


It may be desirable to avoid placing carbonated water in frack stages close to the heel 220 to prevent immediate recycling in case CO2 is not displaced from the well and/or packers are not isolating between stages. Further, carbonated water could be added to only toe 222 stages (or only heel 220 stages) to pinpoint the onset of drainage from a particular well section.


Carbonated water could be added during primary stimulation or into depleted wells during EOR screening. For example, injecting carbonated water into depleted wells to check for CO2 arrival at the neighboring wells could be used to prove or disprove zonal isolation.


Routine compositional checks of produced oil and gas may be performed to determine the amount of CO2 that has been recycled. Based on material balance, these measurements versus time provide a way to quantify to regulators the amount of permanently sequestered CO2.


The use of liquid CO2 may be desirable in certain situations. Liquid CO2 could potentially be trucked to a frac site, added into water, and pumped into the CO2 injection well by regular frac pumps/compressors.


In an exemplary embodiment, liquid CO2 may be injected at low pressure (e.g., ˜50 psia) between primer pumps and frac pumps on the “dirty” side using very cold CO2 (e.g., <−80° F.). Alternatively, higher injection pressures (e.g., ˜500 psia) may allow CO2 to be stored at warmer temperatures (e.g., <30° F.).


While the injection of carbonated water and detection of CO2 is specifically discussed herein, other substances may also be injected into an injection well and used to identify hydraulic connections. Examples of other substances that could be used include carbon monoxide (CO), nitrogen, hydrogen, or toluene. Those of ordinary skill in the art will be able to determine which substances or combinations thereof would provide for identification of hydraulic connections in specific situations.



FIG. 6 is a block diagram of an exemplary cluster computing system 600 that may be utilized to implement at least a portion of the present techniques. The exemplary cluster computing system 600 shown in FIG. 6 has four computing units 602A, 602B, 602C, and 602D, each of which may perform calculations for a portion of the present techniques. However, one of ordinary skill in the art will recognize that the cluster computing system 600 is not limited to this configuration, as any number of computing configurations may be selected. For example, a smaller analysis may be run on a single computing unit, such as a workstation, while a large calculation may be run on a cluster computing system 600 having tens, hundreds, or even more computing units.


The cluster computing system 600 may be accessed from any number of client systems 604A and 604B over a network 606, for example, through a high-speed network interface 608. The computing units 602A to 602D may also function as client systems, providing both local computing support and access to the wider cluster computing system 600.


The network 606 may include a local area network (LAN), a wide area network (WAN), the Internet, or any combinations thereof. Each client system 604A and 604B may include one or more non-transitory, computer-readable storage media for storing the operating code and program instructions that are used to implement at least a portion of the present techniques, as described further with respect to the non-transitory, computer-readable storage media of FIG. 6. For example, each client system 604A and 604B may include a memory device 610A and 610B, which may include random access memory (RAM), read only memory (ROM), and the like. Each client system 604A and 604B may also include a storage device 612A and 612B, which may include any number of hard drives, optical drives, flash drives, or the like.


The high-speed network interface 608 may be coupled to one or more buses in the cluster computing system 600, such as a communications bus 614. The communication bus 614 may be used to communicate instructions and data from the high-speed network interface 608 to a cluster storage system 616 and to each of the computing units 602A to 602D in the cluster computing system 600. The communications bus 614 may also be used for communications among the computing units 602A to 602D and the cluster storage system 616. In addition to the communications bus 614, a high-speed bus 618 can be present to increase the communications rate between the computing units 602A to 602D and/or the cluster storage system 616.


In some embodiments, the one or more non-transitory, computer-readable storage media of the cluster storage system 616 include storage arrays 620A, 620B, 620C and 620D for the storage of models, data. visual representations, results (such as graphs, charts, and the like used to convey results obtained using the present techniques), code, and other information concerning the implementation of at least a portion of the present techniques. The storage arrays 620A to 620D may include any combinations of hard drives, optical drives, flash drives, or the like.


Each computing unit 602A to 602D includes at least one processor 622A, 622B, 622C and 622D and associated local non-transitory, computer-readable storage media, such as a memory device 624A, 624B, 624C and 624D and a storage device 626A, 626B, 626C and 626D, for example. Each processor 622A to 622D may be a multiple core unit, such as a multiple core central processing unit (CPU) or a graphics processing unit (GPU). Each memory device 624A to 624D may include ROM and/or RAM used to store program instructions for directing the corresponding processor 622A to 622D to implement at least a portion of the present techniques. Each storage device 626A to 626D may include one or more hard drives, optical drives, flash drives, or the like. In addition, each storage device 626A to 626D may be used to provide storage for models, intermediate results, data, images, or code used to implement at least a portion of the present techniques.


The present techniques are not limited to the architecture or unit configuration illustrated in FIG. 6. For example, any suitable processor-based device may be utilized for implementing at least a portion of the embodiments described herein, including (without limitation) personal computers, laptop computers, computer workstations, mobile devices, and multi-processor servers or workstations with (or without) shared memory. Moreover, the embodiments described herein may be implemented, at least in part, on application specific integrated circuits (ASICs) or very-large-scale integrated (VLSI) circuits. In fact, those skilled in the art may utilize any number of suitable structures capable of executing logical operations according to the embodiments described herein.



FIG. 7 is a block diagram of an exemplary non-transitory, computer-readable storage medium 700 that may be used for the storage of data and modules of program instructions for implementing at least a portion of the present techniques. The non-transitory, computer-readable storage medium 700 may include a memory device, a hard disk, and/or any number of other devices, as described herein. A processor 702 may access the non-transitory, computer-readable storage medium 700 over a bus or network 704. While the non-transitory, computer-readable storage medium 700 may include any number of modules for implementing the present techniques, in some embodiments, the non-transitory, computer-readable storage medium 700 includes an inter-well parameter detection module 706 for performing the techniques described herein (and/or any suitable variations thereof). Moreover, the inter-well parameter detection module 706 may be adapted to analyze data representing the presence and amount of CO2 received via hydraulic connections between one or more CO2 recipient wells and one or more CO2 injection wells, as described herein.


In one or more embodiments, the present techniques may be susceptible to various modifications and alternative forms, such as the following embodiments as noted in paragraphs 1 to 24:


1. A method for detecting parameters corresponding to a hydraulic connection between wells in a reservoir, comprising: injecting carbonated water into a CO2 injection well; identifying a presence of the carbonated water around a CO2 recipient well; and determining at least one parameter corresponding to the hydraulic connection between the CO2 injection well and the CO2 recipient well based on the presence of the carbonated water around the CO2 recipient well.


2. The method of paragraph 1, wherein identifying the presence of carbonated water comprises measuring a quantity of CO2 contained in the carbonated water.


3. The method of paragraphs 1 or 2, wherein identifying the presence of the carbonated water comprises measuring gas into which the carbonated water has been dissolved.


4. The method of any of paragraphs 1 to 3, wherein identifying the presence of carbonated water comprises measuring oil into which the carbonated water has been dissolved.


5. The method of any of paragraphs 1 to 4, comprising mixing an identifying agent into the carbonated water prior to injecting the carbonated water into the CO2 injection well.


6. The method of any of paragraphs 1 to 5, wherein the identifying agent comprises a C13 isotope.


7. The method of any of paragraphs 1 to 6, wherein the carbonated water comprises a homogeneous mixture.


8. The method of any of paragraphs 1 to 7, comprising mapping the hydraulic connection between the CO2 injection well and the CO2 recipient well.


9. The method of any of paragraphs 1 to 8, wherein the reservoir has multiple CO2 recipient wells.


10. The method of any of paragraphs 1 to 9, comprising generating a well spacing plan based on the hydraulic connection between the CO2 injection well and the CO2 recipient well.


11. The method of any of paragraph 10, comprising drilling at least one well in accordance with the well spacing plan.


12. The method of any of paragraphs 1 to 11, wherein identifying the presence of the carbonated water is performed by a fluid flow device.


13. The method of any of paragraphs 1 to 12, comprising performing at least one of a hydraulic fracturing operation or a hydrocarbon production operation based on hydraulic connection between the CO2 injection well and the CO2 recipient well.


14. The method of any of paragraphs 1 to 13, comprising periodically monitoring the presence of CO2 at the CO2 recipient well.


15. A well system, comprising: a pump for injecting carbonated water into a CO2 injection well in order to permit detecting of parameters corresponding to a hydraulic connection between the CO2 injection well and a CO2 recipient well; a detection device that identifies a presence of the carbonated water around the CO2 recipient well; and a computing device that determines at least one parameter corresponding to the hydraulic connection between the CO2 injection well and the CO2 recipient well based on the presence of the carbonated water around the CO2 recipient well.


16. The well system of paragraph 15, wherein the presence of carbonated water is identified by measuring a quantity of CO2 contained in the carbonated water.


17. The well system of paragraphs 15 or 16, wherein the presence of the carbonated water is identified by measuring gas into which the carbonated water has been dissolved.


18. The well system of any of paragraphs 15 to 17, wherein the presence of carbonated water is identified by measuring oil into which the carbonated water has been dissolved.


19. The well system of any of paragraphs 15 to 18, wherein an identifying agent is mixed into the carbonated water prior to injecting the carbonated water into the CO2 injection well.


20. The well system of any of paragraphs 15 to 19, wherein the identifying agent comprises a C13 isotope.


21. The well system of any of paragraphs 15 to 20, wherein the carbonated water comprises a homogeneous mixture.


22. The well system of any of paragraphs 15 to 21, wherein the computing device maps the hydraulic connection between the CO2 injection well and the CO2 recipient well.


23. The well system of any of claims 15 to 22, wherein the computing device generates a well spacing plan based on the hydraulic connection between the CO2 injection well and the CO2 recipient well.


24. A method for detecting parameters corresponding to a hydraulic connection between wells in a reservoir, comprising: injecting a substance dissolved in water into an injection well, the substance selected from a group consisting of carbon monoxide, nitrogen, hydrogen or toluene; identifying a presence of the substance around a recipient well; and determining at least one parameter corresponding to the hydraulic connection between the injection well and the recipient well based on the presence of the substance water around the recipient well.


While the embodiments described herein are well-calculated to achieve the advantages set forth, it will be appreciated that such embodiments are susceptible to modification, variation, and change without departing from the spirit thereof. In other words, the particular embodiments described herein are illustrative only, as the teachings of the present techniques may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Moreover, the systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Indeed, the present techniques include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

Claims
  • 1. A method for detecting parameters corresponding to a hydraulic connection between wells in a reservoir, comprising: injecting carbonated water into a CO2 injection well;identifying a presence of the carbonated water around a CO2 recipient well; anddetermining at least one parameter corresponding to the hydraulic connection between the CO2 injection well and the CO2 recipient well based on the presence of the carbonated water around the CO2 recipient well.
  • 2. The method of claim 1, wherein identifying the presence of carbonated water comprises measuring a quantity of CO2 contained in the carbonated water.
  • 3. The method of claim 1, wherein identifying the presence of the carbonated water comprises measuring gas into which the carbonated water has been dissolved.
  • 4. The method of claim 1, wherein identifying the presence of carbonated water comprises measuring oil into which the carbonated water has been dissolved.
  • 5. The method of claim 1, comprising mixing an identifying agent into the carbonated water prior to injecting the carbonated water into the CO2 injection well.
  • 6. The method of claim 5, wherein the identifying agent comprises a C13 isotope.
  • 7. The method of claim 1, wherein the carbonated water comprises a homogeneous mixture.
  • 8. The method of claim 1, comprising mapping the hydraulic connection between the CO2 injection well and the CO2 recipient well.
  • 9. The method of claim 1, wherein the reservoir has multiple CO2 recipient wells.
  • 10. The method of claim 1, comprising generating a well spacing plan based on the hydraulic connection between the CO2 injection well and the CO2 recipient well.
  • 11. The method of claim 10, comprising drilling at least one well in accordance with the well spacing plan.
  • 12. The method of claim 1, wherein identifying the presence of the carbonated water is performed by a fluid flow device.
  • 13. The method of claim 1, comprising performing at least one of a hydraulic fracturing operation or a hydrocarbon production operation based on hydraulic connection between the CO2 injection well and the CO2 recipient well.
  • 14. The method of claim 1, comprising periodically monitoring the presence of CO2 at the CO2 recipient well.
  • 15. A well system, comprising: a pump for injecting carbonated water into a CO2 injection well in order to permit detecting of parameters corresponding to a hydraulic connection between the CO2 injection well and a CO2 recipient well;a detection device that identifies a presence of the carbonated water around the CO2 recipient well; anda computing device that determines at least one parameter corresponding to the hydraulic connection between the CO2 injection well and the CO2 recipient well based on the presence of the carbonated water around the CO2 recipient well.
  • 16. The well system of claim 15, wherein the presence of carbonated water is identified by measuring a quantity of CO2 contained in the carbonated water.
  • 17. The well system of claim 15, wherein the presence of the carbonated water is identified by measuring gas into which the carbonated water has been dissolved.
  • 18. The well system of claim 15, wherein the presence of carbonated water is identified by measuring oil into which the carbonated water has been dissolved.
  • 19. The well system of claim 15, wherein an identifying agent is mixed into the carbonated water prior to injecting the carbonated water into the CO2 injection well.
  • 20. The well system of claim 19, wherein the identifying agent comprises a C13 isotope.
  • 21. The well system of claim 15, wherein the carbonated water comprises a homogeneous mixture.
  • 22. The well system of claim 15, wherein the computing device maps the hydraulic connection between the CO2 injection well and the CO2 recipient well.
  • 23. The well system of claim 15, wherein the computing device generates a well spacing plan based on the hydraulic connection between the CO2 injection well and the CO2 recipient well.
  • 24. A method for detecting parameters corresponding to a hydraulic connection between wells in a reservoir, comprising: injecting a substance dissolved in water into an injection well, the substance selected from a group consisting of carbon monoxide, nitrogen, hydrogen or toluene;identifying a presence of the substance around a recipient well; anddetermining at least one parameter corresponding to the hydraulic connection between the injection well and the recipient well based on the presence of the substance water around the recipient well.
CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to and the benefit of U.S. Provisional Application No. 63/499,586, entitled “SYSTEM AND METHOD FOR CARBONATED WATER INJECTION FOR PRODUCTION SURVEILLANCE AND WELL STIMULATION,” having a filing date of May 2, 2023, the disclosure of which is incorporated herein by reference in its entirety.

Provisional Applications (1)
Number Date Country
63499586 May 2023 US