System and Method for Determining Parameters corresponding to Hydraulic Connection between Monitor Well and Treatment Well

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 a monitor well and a treatment well.

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. However, hydraulic fractures are generally thousands, if not tens of thousands, of feet below the surface. Thus, their properties are difficult to directly and effectively measure.

SUMMARY OF THE INVENTION

An embodiment described herein provides a method for detecting parameters corresponding to a hydraulic connection between a monitor well and a treatment well. The method includes hydraulic fracturing a stage of a treatment well to form hydraulic fractures extending into a surrounding formation, where at least a portion of the hydraulic fractures enable a hydraulic connection between the treatment well and the monitor well that is located in the same field as the treatment well or in an adjacent field. The method also includes measuring fluid influx data corresponding to the wellbore of the monitor well during the hydraulic fracturing of the stage of the treatment well, as well as determining one or more parameters corresponding to the hydraulic connection between the treatment well and the monitor well using the measured fluid influx data.

Another embodiment described herein provides a monitor well that includes a wellbore that extends within a subsurface region and a fluid influx sensor that is configured to measure fluid influx data corresponding to the wellbore, where the fluid influx data correspond to a hydraulic connection between the monitor well and a treatment well, and where the hydraulic connection is formed via hydraulic fractures that originate from the treatment well and propagate through the subsurface region. The monitor well also includes a controller programmed to utilize the measured fluid influx data to determine one or more parameters corresponding to the hydraulic connection between the treatment well and the monitor 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 treatment well and a monitor well that may be utilized in accordance with the present techniques;

FIG. 2 is a schematic view of an exemplary embodiment of the treatment well and the monitor well of FIG. 1;

FIG. 3A is a simplified schematic view showing a first stage of a treatment well, a corresponding stage of a first monitor well, and a corresponding stage of a second monitor well that may be used to implement the present techniques;

FIG. 3B is a graph showing the measured pressure response in the first monitor well during hydraulic fracturing of the first stage of the treatment well;

FIG. 3C is a graph showing the measured pressure response in the second monitor well during hydraulic fracturing of the first stage of the treatment well;

FIG. 4 is a process flow diagram of an exemplary method for detecting parameters corresponding to a hydraulic connection between a monitor well and a treatment well;

FIG. 5 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. 6 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 ease 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.

Turning now to details of the present techniques, as described above, 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. However, according to current techniques, there is limited ability to measure or determine the properties of hydraulic fractures. Accordingly, the present techniques alleviate this difficulty and provide related advantages as well. In particular, the inter-well parameter detection techniques described herein provide for the detection of various parameters corresponding to a monitor well that is in hydraulic communication with a treatment well. More specifically, the present techniques leverage fluid influx data measured via open perforations within a monitor well to detect various parameters corresponding to a hydraulic connection between the monitor well and the treatment well, where such hydraulic connection is formed via hydraulic fractures initiated from the treatment well. For example, the fluid influx data may be leveraged to detect hydraulic fracture arrival at the monitor well, 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 monitor well, to determine the conductivities of the hydraulic fractures, to determine the total (or approximate) number of hydraulic connections between the monitor well and the treatment well, to detect proppant arrival at the monitor well, to determine the intensity of the hydraulic connection(s) between the treatment well and the monitor well, and/or to determine the degree of isolation integrity in the monitor well.

According to the inter-well parameter detection techniques described herein, the treatment well and the monitor well are located in the same field or in adjacent fields. Moreover, the treatment well and the monitor 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 with the monitor well via propagation of the hydraulic fracture(s) through the subsurface region in the direction of the monitor well. In various embodiments, such hydraulic connections are provided through hydraulic communication between the perforations (and corresponding hydraulic fractures) within the stage of the treatment well and one or more perforations within a corresponding stage of the monitor well (and/or one or more open ports, sleeves, slots, or the like within the monitor well).

Moreover, in some embodiments, the configuration of the treatment well and the monitor well(s) is specifically controlled to enable efficient implementation of the present techniques. In such embodiments, this may include drilling the treatment wellbore and the monitor 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. 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 treatment well and the monitor well. In general, the present techniques can be applied for any multi-well configuration in which one or more hydraulic fractures originating from a treatment well are capable of propagating to the extent of providing hydraulic communication with at least one monitor well.

In some embodiments, the monitor well described herein has not been previously hydraulically fractured. For example, the monitor well may be entirely (or partially) perforated but not yet hydraulically fractured. In other embodiments, the monitor 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 monitor well (or some substantial portion thereof) has already undergone a hydraulic fracturing operation.

In various embodiments, hydraulic fracture(s) are first initiated at the treatment well, and such hydraulic fracture(s) are used to establish hydraulic communication between the monitor well and the treatment 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 monitor 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 monitor 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 time of proppant arrival at the monitor well, the intensity of the hydraulic connection(s) between the treatment well and the monitor well, the conductivity of one or more of the hydraulic fractures, and/or the degree of isolation integrity in the monitor 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, the fracture proppant loading, 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 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 monitor 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 treatment well and a monitor well that may be utilized in accordance with the present techniques, while FIG. 2 is a schematic view of an exemplary embodiment of the treatment well and the monitor well of FIG. 1. 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 treatment well 100 and a monitor well 102 are provided. In various embodiments, the treatment 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 monitor well 102 may be a separate producer well, a dedicated monitor well, or any other suitable type of well that is offset from the treatment well 100 and is configured to measure fluid influx data according to the present techniques. As described above, according to embodiments described herein, the monitor well 102 is a well that has not yet undergone a hydraulic fracturing process.

Specifically, when fracturing fluid is injected into the treatment well 100 during the hydraulic fracturing process, as indicated by arrow 104, the fracturing fluid flows through perforations 106 within the corresponding stage of the treatment well 100, creating 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 treatment well 100 and the monitor 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 treatment well 100 and the perforations 110 within the corresponding stage of the monitor well 102. Moreover, in various embodiments, the initiation of such hydraulic connections enables pressure signals caused by the formation of the hydraulic fractures 108 to travel through the fluid column within the wellbore of the monitor well 102, as indicated by arrow 112, and to be measured via a pressure transducer 114 that is coupled to the fluid column within the wellbore of the monitor well 102. Those skilled in the art will appreciate that, while such pressure transducer 114 is depicted in FIG. 1 as being at or near the surface or wellhead of the monitor well 102, the pressure transducer 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 pressure transducers 114 (e.g., potentially one or more arrays of pressure transducers 114) may be used. Furthermore, it should be noted that, while a pressure transducer 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 monitor well 102.

According to the embodiment shown in FIG. 1, the pressure data recorded by the pressure transducer 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 the hydraulic fractures at the monitor well 102, 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 arrival of proppant at the monitor well 102, 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 monitor well 102. Moreover, in some embodiments, the pressure data (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, the fracture proppant loading, 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 treatment well 100 and the monitor 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 toe 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 is pumped down the wellbore 200 of the treatment 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 treatment 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 treatment 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 treatment well 100, which is located near the toe 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 treatment well 100, each stage of the treatment 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 is used to create perforation clusters 252A, 252B, 252C, 252D, and 252E within a corresponding stage 254 of the monitor well 102. In some embodiments, the perforation clusters 252A-E within the wellbore 200 of the monitor well 102 are designed to approximately align with the perforation clusters within the wellbore 200 of the treatment 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 treatment well 100 or the monitor 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 treatment 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 monitor well 102 (and/or to one or more open ports, sleeves, and/or slots corresponding to the monitor 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 pressure transducer according to the exemplary embodiment shown in FIG. 2) at the monitor well 102 to measure fluid influx data corresponding to the formation of such hydraulic fractures 256A-E. Such fluid influx 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 treatment 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 monitor 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 treatment 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. 3A is a simplified schematic view showing a first stage 300 of a treatment well 302, a corresponding stage 304 of a first monitor well 306, and a corresponding stage 308 of a second monitor well 310 that may be used to implement the present techniques. FIG. 3B is a graph 312 showing the measured pressure response in the first monitor well 306 during hydraulic fracturing of the first stage 300 of the treatment well 302, and FIG. 3C is a graph 314 showing the measured pressure response in the second monitor well 310 during hydraulic fracturing of the first stage 300 of the treatment well 302. Specifically, the graph 312 of FIG. 3B shows a change in pressure of approximately 1100 pounds per square inch (psi) in the fluid column of the first monitor well 306, as indicated by arrow 316, while the graph 314 of FIG. 3C shows a change in pressure of approximately 20 psi in the fluid column of the second monitor well 310, as indicated by arrow 316. These strong pressure signals indicate direct hydraulic communication between the treatment well 302 and each of the monitor wells 306 and 310. Therefore, as described herein, parameters relating to the hydraulic connection(s) between the treatment well 302 and the monitor well 306 or 310 (including parameters relating to the hydraulic fractures originating at the treatment well 302) can be determined using pressure measurements taken with respect to the fluid column within the wellbore of the corresponding monitor well 306 or 310.

FIG. 4 is a schematic view of an exemplary method 400 for detecting parameters corresponding to a hydraulic connection between a monitor well and a treatment well. 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. 5, 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 treatment well 100 and the monitor well 102 described herein.

The method 400 begins at block 402, at which a stage of a treatment well is hydraulically fractured to form hydraulic fractures extending into a surrounding formation, where at least a portion of the hydraulic fractures enable one or more hydraulic connections between the treatment well and the monitor well that is located in the same field as the treatment well or in an adjacent field (e.g., via hydraulic communication between the perforations within the treatment well and corresponding perforations within the monitor well). At block 404, fluid influx data corresponding the wellbore of the monitor well are measured during the hydraulic fracturing of the stage of the treatment well. In various embodiments, such fluid influx data are measured using one or more fluid influx sensors that are positioned within the wellbore and/or at the surface. As an example, for embodiments in which one or more pressure transducers are utilized, such pressure transducer(s) may be coupled to the fluid column within the wellbore of the monitor well. Moreover, in various embodiments, such fluid influx data are measured repeatedly or continuously during the hydraulic fracturing of the stage of the treatment well. In some embodiments, such fluid influx sensor includes a pressure transducer, and the fluid influx data include pressure data. In other embodiments, such fluid influx sensor includes a fiber optic cable, and the fluid influx data include strain data.

At block 406, one or more parameters corresponding to the hydraulic connection between the treatment well and the monitor well are determined using the measured fluid influx data. In some embodiments, this includes detecting hydraulic fracture arrival at the monitor well using the measured fluid influx data. Additionally or alternatively, in some embodiments, this includes determining the fracture growth pattern of one or more of the hydraulic fractures, the number of hydraulic fractures that have arrived at the monitor well, the number of hydraulic connections between the monitor well and the treatment 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 proppant arrival at the monitor well, the intensity of the hydraulic connection(s) between the treatment well and the monitor well, and/or the degree of isolation integrity in the monitor 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 fluid influx 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 treatment well and the monitor 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 monitor wells that are located in the same field as the treatment 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 treatment well and perforations within a corresponding stage of the monitor well. In such embodiments, the method 400 may include configuring the treatment well and the monitor well such that the perforations within the stage of the treatment well and the perforations within the corresponding stage of the monitor 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 block diagram of an exemplary cluster computing system 500 that may be utilized to implement at least a portion of the present techniques. The exemplary cluster computing system 500 shown in FIG. 5 has four computing units 502A, 502B, 502C, and 502D, 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 500 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 500 having tens, hundreds, or even more computing units.

The cluster computing system 500 may be accessed from any number of client systems 504A and 504B over a network 506, for example, through a high-speed network interface 508. The computing units 502A to 502D may also function as client systems, providing both local computing support and access to the wider cluster computing system 500.

The network 506 may include a local area network (LAN), a wide area network (WAN), the Internet, or any combinations thereof. Each client system 504A and 504B 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 504A and 504B may include a memory device 510A and 510B, which may include random access memory (RAM), read only memory (ROM), and the like. Each client system 504A and 504B may also include a storage device 512A and 512B, which may include any number of hard drives, optical drives, flash drives, or the like.

The high-speed network interface 508 may be coupled to one or more buses in the cluster computing system 500, such as a communications bus 514. The communication bus 514 may be used to communicate instructions and data from the high-speed network interface 508 to a cluster storage system 516 and to each of the computing units 502A to 502D in the cluster computing system 500. The communications bus 514 may also be used for communications among the computing units 502A to 502D and the cluster storage system 516. In addition to the communications bus 514, a high-speed bus 518 can be present to increase the communications rate between the computing units 502A to 502D and/or the cluster storage system 516.

In some embodiments, the one or more non-transitory, computer-readable storage media of the cluster storage system 516 include storage arrays 520A, 520B, 520C and 520D 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 520A to 520D may include any combinations of hard drives, optical drives, flash drives, or the like.

Each computing unit 502A to 502D includes at least one processor 522A, 522B, 522C and 522D and associated local non-transitory, computer-readable storage media, such as a memory device 524A, 524B, 524C and 524D and a storage device 526A, 526B, 526C and 526D, for example. Each processor 522A to 522D may be a multiple core unit, such as a multiple core central processing unit (CPU) or a graphics processing unit (GPU). Each memory device 524A to 524D may include ROM and/or RAM used to store program instructions for directing the corresponding processor 522A to 522D to implement at least a portion of the present techniques. Each storage device 526A to 526D may include one or more hard drives, optical drives, flash drives, or the like. In addition, each storage device 526A to 526D 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. 5. 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. 6 is a block diagram of an exemplary non-transitory, computer-readable storage medium 600 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 600 may include a memory device, a hard disk, and/or any number of other devices, as described herein. A processor 602 may access the non-transitory, computer-readable storage medium 600 over a bus or network 604. While the non-transitory, computer-readable storage medium 600 may include any number of modules for implementing the present techniques, in some embodiments, the non-transitory, computer-readable storage medium 500 includes an inter-well parameter detection module 606 for performing the techniques described herein (and/or any suitable variations thereof).

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 29:

1. A method for detecting parameters corresponding to a hydraulic connection between a monitor well and a treatment well, including: hydraulic fracturing a stage of a treatment well to form hydraulic fractures extending into a surrounding formation, where at least a portion of the hydraulic fractures enable a hydraulic connection between the treatment well and a monitor well that is located in a same field as the treatment well or in an adjacent field; during the hydraulic fracturing of the stage of the treatment well, measuring fluid influx data corresponding to a wellbore of the monitor well; and determining at least one parameter corresponding to the hydraulic connection between the treatment well and the monitor well using the measured fluid influx data.

2. The method of paragraph 1, where determining the at least one parameter corresponding to the hydraulic connection between the treatment well and the monitor well using the measured fluid influx data includes detecting hydraulic fracture arrival at the monitor well using the measured fluid influx data.

3. The method of paragraph 1 or 2, where determining the at least one parameter corresponding to the hydraulic connection between the treatment well and the monitor well using the measured fluid influx data includes determining at least one of: a fracture growth pattern of at least one of the hydraulic fractures; a number of hydraulic fractures that have arrived at the monitor well; an azimuth of at least one of the hydraulic fractures; or a conductivity of at least one of the hydraulic fractures.

4. The method of any of paragraphs 1 to 3, where determining the at least one parameter corresponding to the hydraulic connection between the treatment well and the monitor well using the measured fluid influx data includes determining at least one of: proppant arrival at the monitor well; an intensity of the hydraulic connection between the treatment well and the monitor well; or a degree of isolation integrity in the monitor well.

5. The method of any of paragraphs 1 to 4, where determining the at least one parameter corresponding to the hydraulic connection between the treatment well and the monitor well using the measured fluid influx data includes determining changes in at least a portion of the hydraulic fractures over time using the measured fluid influx data.

6. The method of any of paragraphs 1 to 5, including coupling the measured fluid influx data to a hydraulic fracture model that represents a fracture system including the hydraulic fractures.

7. The method of any of paragraphs 1 to 6, where determining the at least one parameter corresponding to the hydraulic connection between the treatment well and the monitor well using the measured fluid influx data includes determining at least one of: a post-shut-in continuity of the hydraulic connection between the treatment well and the monitor well; or a post-shut-in conductivity of the hydraulic connection between the treatment well and the monitor well.

8. The method of any of paragraphs 1 to 7, including performing the method for multiple monitor wells that are located in the same field as the treatment well or in at least one adjacent field.

9. The method of any of paragraphs 1 to 8, where the hydraulic connection is provided between perforations within the stage of the treatment well and perforations within a corresponding stage of the monitor well, and where the method further includes configuring the treatment well and the monitor well such that the perforations within the stage of the treatment well and the perforations within the corresponding stage of the monitor well are offset by less than or equal to a predetermined distance in at least one direction.

10. The method of any of paragraphs 1 to 9, including measuring the fluid influx data corresponding to the wellbore of the monitor well using at least one fluid influx sensor.

11. The method of any of paragraphs 1 to 10, including measuring the fluid influx data corresponding to the wellbore of the monitor well repeatedly or continuously during the hydraulic fracturing of the stage of the treatment well.

12. The method of any of paragraphs 1 to 11, including generating a well spacing plan based on the at least one parameter.

13. The method of paragraph 12, including drilling at least one well in accordance with the well spacing plan.

14. The method of any of paragraphs 1 to 13, including performing at least one of a hydraulic fracturing operation or a hydrocarbon production operation in accordance with the at least one parameter.

15. A monitor well, including: a wellbore that extends within a subsurface region; a fluid influx sensor that is configured to measure fluid influx data corresponding to the wellbore, where the fluid influx data correspond to a hydraulic connection between the monitor well and a treatment well, and where the hydraulic connection is formed via hydraulic fractures that originate from the treatment well and propagate through the subsurface region; and a controller programmed to utilize the measured fluid influx data to determine at least one parameter corresponding to the hydraulic connection between the treatment well and the monitor well.

16. The monitor well of paragraph 15, where the controller is programmed to utilize the measured fluid influx data to determine the at least one parameter corresponding to the hydraulic connection between the treatment well and the monitor well by detecting hydraulic fracture arrival at the monitor well using the measured fluid influx data.

17. The monitor well of paragraph 15 or 16, where the controller is programmed to utilize the measured fluid influx data to determine the at least one parameter corresponding to the hydraulic connection between the treatment well and the monitor well by determining at least one of the following parameters relating to the hydraulic fractures: a fracture growth pattern of at least one of the hydraulic fractures; a number of hydraulic fractures that have arrived at the monitor well; an azimuth of at least one of the hydraulic fractures; or a conductivity of at least one of the hydraulic fractures.

18. The monitor well of any of paragraphs 15 to 17, where the controller is programmed to utilize the measured fluid influx data to determine the at least one parameter corresponding to the hydraulic connection between the treatment well and the monitor well by determining at least one of: proppant arrival at the monitor well; an intensity of the at least one hydraulic connection between the treatment well and the monitor well; or a degree of isolation integrity in the monitor well.

19. The monitor well of any of paragraphs 15 to 18, where the controller is programmed to utilize the measured fluid influx data to determine the at least one parameter corresponding to the hydraulic connection between the treatment well and the monitor well by detecting changes in at least a portion of the hydraulic fractures over time, as measured from the monitor well.

20. The monitor well of any of paragraphs 15 to 19, where the controller is programmed to couple the measured fluid influx data to a hydraulic fracture model that represents a fracture system including the hydraulic fractures.

21. The monitor well of any of paragraphs 15 to 20, where the controller is programmed to utilize the measured fluid influx data to determine the at least one parameter corresponding to the hydraulic connection between the treatment well and the monitor well by determining at least one of: a post-shut-in continuity of the hydraulic connection between the treatment well and the monitor well; or a post-shut-in conductivity of the hydraulic connection between the treatment well and the monitor well.

22. The monitor well of any of paragraphs 15 to 21, where the fluid influx sensor includes at least one of a pressure transducer or a fiber optic cable.

23. The monitor well of any of paragraphs 15 to 22, where the controller is programmed to: generate a well spacing plan based on the at least one parameter; and cause the drilling of at least one well in accordance with the well spacing plan.

24. A non-transitory, computer-readable storage medium, including program instructions that are executable by a processor to cause the processor to: receive fluid influx data corresponding to a wellbore of a monitor well during hydraulic fracturing of a treatment well, where at least a portion of hydraulic fractures created during the hydraulic fracturing of the treatment well provide at least one hydraulic connection between the treatment well and the monitor well, and where the fluid influx data are measured via a fluid influx sensor; and detect hydraulic fracture arrival at the monitor well using the received fluid influx data.

25. The non-transitory, computer-readable storage medium of paragraph 24, further including program instructions that are executable by the processor to cause the processor to determine at least one additional parameter relating to the hydraulic fractures using the received fluid influx data, where the at least one additional parameter includes at least one of: a fracture growth pattern of at least one of the hydraulic fractures; a number of hydraulic fractures that have arrived at the monitor well; a number of hydraulic connections between the monitor well and the treatment well; an azimuth of at least one of the hydraulic fractures; proppant arrival at the monitor well; an intensity of the at least one hydraulic connection between the treatment well and the monitor well; a conductivity of at least one of the hydraulic fractures; or a degree of isolation integrity in the monitor well.

26. The non-transitory, computer-readable storage medium of paragraph 24 or 25, further including program instructions that are executable by the processor to cause the processor to determine changes in at least a portion of the hydraulic fractures over time using the received fluid influx data.

27. The non-transitory, computer-readable storage medium of any of paragraphs 24 to 26, further including program instructions that are executable by the processor to cause the processor to couple the received fluid influx data to a hydraulic fracture model that represents a fracture system including the hydraulic fractures.

28. The non-transitory, computer-readable storage medium of any of paragraphs 24 to 27, further including program instructions that are executable by the processor to cause the processor to utilize the received fluid influx data to determine at least one of: a post-shut-in continuity of the at least one hydraulic connection between the treatment well and the monitor well; or a post-shut-in conductivity of the at least one hydraulic connection between the treatment well and the monitor well.

29. The non-transitory, computer-readable storage medium of any of paragraphs 24 to 28, further including program instructions that are executable by the processor to cause the processor to: receive fluid influx data corresponding to the wellbores of multiple monitor wells during the hydraulic fracturing of the treatment well; and detect hydraulic fracture arrival at each monitor well using the corresponding received fluid influx data.

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.

System and Method for Determining Parameters corresponding to Hydraulic Connection between Monitor Well and Treatment Well

Information

Publication Number

Date Filed

Date Published

Inventors

Original Assignees

CPC

International Classifications

Abstract

Description

Claims

CROSS-REFERENCE TO RELATED APPLICATION

Provisional Applications (1)