SYSTEM AND METHOD FOR REDUCING AND MANAGING SURFACE PRESSURE OF CASING STRINGS

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to and the benefit of U.S. Provisional Application No. 63/673,896, entitled “SYSTEM AND METHOD FOR REDUCING AND MANAGING SURFACE PRESSURE OF CASING STRINGS,” having a filing date of Jul. 22, 2024, the disclosure of which is incorporated herein by reference in its entirety.

FIELD

The techniques described herein relate generally to the field of hydrocarbon well completions. More specifically, the techniques described herein relate to reducing pressure on casing strings in hydrocarbon wells.

BACKGROUND

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.

Conventional and unconventional wells include multiple casing strings that are typically supported by cement. For example, the casing strings may be pipes having different diameters that are placed within one another for specific purposes within a well. Where the casing strings experience elevated surface pressures due to the presence of a micro-annulus or crack in the cement sheath of a casing string, there is a need for a solution to reduce and manage the pressures. Conventional methods such as pumping cement in an attempt to fix the micro-annuli are costly and difficult to successfully implement.

SUMMARY

An embodiment provided herein relates to a method for reducing pressure in casing strings. The method also includes periodically bleeding off a volume of annuli fluid from a casing string of a well. The method further includes injecting a first brine into the casing string to establish an initial injectivity into a micro-annulus of the casing string.

Another embodiment provided herein relates to a well system. The well system includes a supply tank comprising a brine. The well system also includes a pump fluidically coupled to the supply tank and a casing string of a well. The well system further includes a pressure switch fluidically coupled to the pump, wherein the pressure switch is to switch off the pump in response to detecting that a surface pressure at the casing string of the well has exceeded a threshold surface pressure.

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 well with an attached annulus injection unit, in accordance with the present techniques;

FIG. 2 is a schematic view of an exemplary embodiment of a well with annulus injection unit of FIG. 1 shown in the context of a reservoir;

FIG. 3 is an illustration showing an example using an annulus injection unit, according to an exemplary embodiment of the present techniques;

FIG. 4 is a detailed schematic illustration showing an annulus injection unit coupled via a surface manifold to a casing string of a single well, according to an exemplary embodiment of the present techniques;

FIG. 5 is a schematic illustration showing an annulus injection unit coupled via a manifold to multiple wells, according to an exemplary embodiment of the present techniques;

FIG. 6 is a process flow diagram of an exemplary method for mitigating high annulus pressure on a well according to the present techniques; and

FIG. 7 is a graph showing a decrease in high casing pressure following injection of sodium bromide, in accordance with 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 term “Christmas tree” refers to a set of valves, spools, and fittings connected to the top of a well to direct and control the flow of formation fluids from the well.

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 wells. For example, the wells may be hydrocarbon wells for which hydrocarbon production operations are to be performed to provide for the extraction of hydrocarbon fluids from a corresponding subterranean formation. In some examples, the wells may include geothermal wells, steam injection wells, disposal wells, water injector wells, gas injector wells, brine or salt recovery wells, monitor wells, and temporarily abandoned wells.

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

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 terms “micro-annulus” and “micro-annuli” refer to one or more cracks in the cement sheath of a cemented casing string. For example, such cracks may develop in one or more casing strings of one or more wells in a field as the result of fluctuations in pressure and temperature over time.

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.

As described above, wells are subject to fluctuations in pressure and temperature. Such fluctuations in pressure and temperature can cause micro-annuli to form within the cement supporting various casing strings of a well, and lead to surface pressure at the one or more annuli between casings to exceed a threshold pressure, such as a pressure close to or significantly below a maximum allowable wellhead operating pressure (MAWOP). For example, in unconventional wells, after the well is drilled down to total depth, and a horizontal casing string is run and cemented, then giant frack skids perform multi-stage pumping operations on the well. In various examples, sometimes anywhere from 45 to 65 or more fracking stages are pumped down such wells to frack the well from the toe which is the end of the well to the heel, which is the beginning of the horizontal section of the well. Such hydraulic fracturing may involve 10,000 lbs. or more of pressure to pump these frack jobs at 100 barrels a minute, with the casing strings being put through cycles of heating and cooling under high pressures.

In some cases, an anomalous high pressure on a casing string in a production phase of a well may be caused by a micro-annulus or crack in the cement sheath of a casing string. Anomalous annulus pressure in the cemented annulus of oil and gas wells can be caused by many factors, including but not limited to: poor hole conditions prior to cementing, loss return zones in the open hole section of a well where casing is being cemented, poor quality cement, variations of pressure and temperature on wells' annuli caused by well production or fracturing processes, or any combination of these factors. As an example of a well's condition that this process is designed to mitigate, a micro-annulus or crack may form in the cement sheath of a casing string's annulus with cement that was placed to isolate formation pressure in the well's annuli. This condition can arise in the annuli of casing strings cemented in conventional and unconventional oil and gas wells. In low permeability reservoir development, multi-stage fracturing at high pressures induces significant variation in downhole pressures and temperatures and this cycling could contribute to the creation of micro-annuli or cracks in the cement sheaths of wells' annuli where the original cementing was sub-optimal.

Some methods attempting to resolve such issues pump cement to completely isolate micro-annuli. However, such pumping of cement involves performing a rig workover, the cost of which has increased dramatically over the years. For example, the cost of performing a rig workover to remediate a well with high casing pressure resulting from a micro-annulus on an unconventional well in the United States may range from $500,000 to $1,000,000 or more. Moreover, there is a chance that such pumping of cement does not actually seal a micro-annulus, which could be causing the increase in surface pressure. For example, when cement is pumped into a well, the cement normally takes the path of least resistance, and the micro-annuli may temporarily close during the pumping before the cement is allowed to enter the micro-annuli. Thus, pumping cement via a rig workover is not only expensive, but has significant chances of failure. In addition, such pumping of cement would likely involve running an additional internal casing patch or liner after cement drill out in many cases, which also reduces the internal diameter of the well. Thus, smaller tubing and/or smaller artificial lift accessories would need to be run back into the well for production. This could significantly reduce the production rate of the well, particularly for gas lifted wells or make electrical submersible pump (ESP) lifted wells less efficient.

Alternatively, some other methods use sealants to seal up such leaks, but the ability to get the sealant to form a plug deep, close to the point of pressure entry, is not readily achievable. In many cases, these sealants might result in a plug being created near ground level and not deep, close to the point of pressure entry into the micro-annulus. As an example, a micro-annulus might only be sealed ˜15 to 20 feet below ground level. In this scenario, if a breach of the casing occurs below a plug at such shallow depths, personnel could be spontaneously exposed to hydrocarbons released at the surface by a well where such a condition was not readily apparent.

The present techniques relate to systems and methods to reduce and stabilize surface pressure at one or more casing strings of any number of wells. The present techniques facilitate the reduction and stabilization of casing string surface pressures to improve the safe operation of affected wells and maintain their productivity by avoiding both workover downtime and the need to potentially install smaller completion equipment following well work to remediate a micro-annulus. The pressure reduction and stabilization techniques described herein provide for the injection of fluid into the annulus of a well in order to reduce and stabilize pressures that may be caused by micro-annuli formed in one or more casing strings of a well.

The pressure reduction and stabilization techniques described herein can be advantageously applied to any high surface pressure scenarios involving one or more casing strings in one or multiple wells. In addition, the present techniques may be applied almost automatically with minimal intervention. Moreover, such intervention, which may include periodically bleeding off annuli fluid volumes, may be performed accordingly to any schedule. In some embodiments, pressure transducers monitor the pressures on the various casing strings and data is sent to the cloud thereby allowing continuous electronic surveillance and historical review. In addition, the annulus injection system is intrinsically safe and simple to operate. In order to strike a balance between making the annulus injection unit inherently safe and yet incorporating some level of automation, an operator performs the casing pressure bleed downs manually, as desired. Following the bleed down, the operator switches the annulus over to the injection pump, which injects brine into the well's annulus to reduce the surface pressure, preferably until an upper threshold of acceptable pressure is reached. Repeated bleeding off and injection may be carried out if needed. The bleeding off and injection can be stopped when a desired target surface pressure (e.g., at or below 100, 200, 400, 500, 600, 800, 1000, 1500, 2000 psi lower than the MAWOP) of the casing string is reached. The target pressure can be, e.g., 500, 600, 800, 1000, 1500, 2000, 2500 psi. At this time, the controller shuts down injection until the next bleed down cycle is performed. The bleed downs and injection cycles can thus be performed on the operator's schedule (no prescribed schedule required), and due to the reliability of the shutdown switch, the operator does not need to be present once the annulus of the well is left open to the injection pump. Thus, the techniques described herein are minimally invasive to operations, do not require expensive manned pumping trucks or skids which would be unable to practically support long-term, low-rate injection and efficiently utilize a reliable pressure switch to safely prevent injection above a casing string's MAWOP. The aspects of the present disclosure, when compared to other solutions, are therefore simple and less expensive, intrinsically safe, have low manpower requirements to operate, do not risk plugging a micro-annulus near the surface which would increase operational risk, allow for continuous monitoring of micro-annulus pressure, and provide flexibility to be used on either single or multiple wells at a single pad and are transferable to other well sites for treatment, as desired.

Turning now to the figures, FIGS. 1 and 2 provide examples of a well 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 an attractor well that may be utilized in accordance with the present techniques, while FIG. 2 is a schematic view of an exemplary embodiment of the 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 well shown in FIG. 1.

Turning first to FIG. 1, a well 100 is provided. In various embodiments, the well 100 is a producer well or any other suitable type of hydrocarbon well. The well 100 includes an annulus injection unit 102 coupled to one or more of the casing strings of the well. The casing strings include a surface casing string 104, an intermediate casing string 106, and a production casing string, 108. As one example, the surface casing string 104 may be tubing having a diameter of about 13 inches and a length of about 3,000 feet. In this example, the intermediate casing string 106 may be tubing having a diameter of about 10 inches and a length of over 10,000 feet. Similarly, the production casing string 108 may have a smaller diameter of about 6 inches and a length of over 20,000 feet. The various casing strings of FIG. 1 are shown being held in place using cement 110. In various embodiments, this cement 110 also fills the intermediate casing annulus between the intermediate casing string 106 and the production casing string 108. The well 100 includes a heel 112 that connects the vertical portion of the well 100 to a horizontal portion 114 of the well.

According to the embodiment shown in FIG. 1, the cement 110 has developed one or more micro-annuli 116. For example, the micro-annuli 116 may have developed as a result of stresses to the cement 110 potentially caused by fluctuations of pressure and temperature associated with various operations on the well. As a result, the surface pressure of the intermediate casing string 106, or any other outer casing string, may have also increased beyond a target pressure, such as a pressure below MAWOP. Such high surface pressure at the casings are highly undesirable and can constitute a safety hazard. Therefore, in various embodiments, the intermediate casing string 106 was bled off to reduce the surface pressure at the casing string exhibiting such high surface pressure, and an annulus injection unit 102 was installed to reduce the surface pressure by injecting a brine, as described herein.

In the present disclosure, the brine injected into the annulus desirably forms a liquid column exerting a pressure (hydrostatic head) at the bottom thereof. The hydrostatic head can be calculated per the following equation (Eq. 1):

Hydrostatic ⁢ head ⁢ ( psi ) = ρ ⁡ ( lb / gal ) * depth tvd ( ft ) * 0.052 ( psi / ft / lb / gal ) Eq . 1

where p is the brine density and depth_tvd a is the true vertical depth of the liquid column. If the hydrostatic head of a column of the brine formed in the casing strings' micro-annulus by displacing fluids into a casing string's micro-annulus is sufficiently high (e.g., approximate to, equal or greater than the bottom hole pressure of a subterranean formation feeding pressure into a micro-annulus), then surface pressure of a casing string may be driven to a target pressure. A high density of the brine of, e.g., at least 1.2 g·cm⁻³, such as from 1.2 g·cm⁻³ to 2.5 g·cm⁻³, can be particularly advantageous in establishing a desired level of hydrostatic of the brine column.

For a horizontal unconventional well with three casing strings as shown in the example of FIG. 1, the well's original drilling program for the mud weights used to drill various hole sections (Surface, Intermediate, Production) can be used as points of reference for brine density selection required to subsequently drive the surface pressure of a casing string to well below its calculated MAWOP (or as low as desired) should a ‘crack’ or pathway develop in a casing string's cemented annulus to the surface. As one example, the mud weights used to drill the intermediate and production hole sections were 10 lb/gal (1.2 g·cm⁻³) and 13.1 lb/gal (1.57 g·cm⁻³), respectively. These maximum mud weights used in drilling various hole sections may be slightly heavier than the pore pressure of the formations drilled to prevent reservoir fluid influx while drilling the well. Therefore, in this example, injecting a full column of either 10 ppg (1.2 g·cm⁻³) or 12.5 ppg (1.5 g·cm⁻³) brine into this well's intermediate casing annulus would have a reasonable chance of driving the surface pressure of the intermediate casing to well below this intermediate casing string's calculated MAWOP pressure, or as low as desired. However, in the case of a micro-annulus or multiple micro-annuli, injectability is not known, and nor is the potential source of the micro-annulus pressure known, unless expensive well logging is performed. Moreover, the exact volume of the micro-annulus between the casing strings to be filled to drive the pressure down is also not known.

In various embodiments, the annulus injection process can start out with the supply tank to the high-pressure pump being supplied with 10 lb/gal (1.2 g·cm⁻³) ppg NaCl brine, preferably inhibited with corrosion mitigation and oxygen scavenger chemicals to prevent downhole corrosion, and injecting the inhibited NaCl into an annulus immediately following casing pressure bleed downs to well below MAWOP pressure (e.g., ˜500 psi). The purpose of injecting the NaCl brine is to determine if injectivity into a well's micro-annulus is possible with a relatively inexpensive and non-hazardous fluid. At the same time, since 10 ppg (1.2 g·cm⁻³) NaCl brine is so inexpensive and readily available, sodium chloride may be preferred over fresh water, because the NaCl brine has a higher density.

Once experience is obtained in injecting the brine, if it is found that the surface pressure on a well's casing string over time is not as low as desired, a decision may be made to swap over to a heavier brine. For example, the heavier brine may preferably be a 12.5 lb/gal NaBr (1.5 g·cm⁻³) aqueous solution having a higher density (e.g., 12.5 lb/gal (1.5 g·cm⁻³), as it is compatible with NaCl, has low corrosion potential, and the combination of these brines does not result in any precipitate solids which may plug the micro-annulus. Both 10 lb/gal (1.2 g·cm⁻³) NaCl and 12.5 lb/gal NaBr (1.5 g·cm⁻³) are fully pumpable at these densities. In various embodiments, the surface pressure on the casing string is a function of: 1) fluids remaining in an annulus, 2) bottom hole pressure and depth at point of ingress, 3) micro-annulus injectability, 4) duration of injection, and 5) micro-annulus volume.

The well 100 described in examples above was one of the deeper TVD unconventional wells. Moreover, most oil and gas fields occur above the region of over-pressure. Therefore, a combination of 10 lb/gal NaCl (1.2 g·cm⁻³) and 12.5 ppg NaBr (1.5 g·cm⁻³) may suffice to get most sustained casing pressures in oil and gas wells' casing strings below a target pressure, such as a pressure below MAWOP, preferably substantially lower than the MAWOP. However, in various embodiments, any combination of brines up to and including 19.2 lb/gal (2.3 g·cm⁻³) ZnBr₂ may be used if the 19.2 lb/gal (2.3 g·cm⁻³) ZnBr₂ can be successfully inhibited for the life of the well and does not substantially raise the risk of forming precipitates which could lead to the formation of a shallow plug as in the case of some of the sealants discussed previously.

Turning now to FIG. 2, the well 100 defines 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 the reservoir 206 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 may 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” if this innermost casing string is simply landed in the bottom of the intermediate casing and not run all the way to the surface. 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 surface also, but, in other embodiments, may be a production liner which 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 wellbore 200 shown in FIG. 2 is completed horizontally, or laterally. A lateral section 218 of the wellbore 200 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 may be 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. The high-pressure slurry 238 may be pumped down the wellbore 200 of the 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.

The wellhead 240 may include any arrangement of pipes and valves for controlling the corresponding well 100. 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 well 100 to other equipment, such as equipment for running a wireline (not shown) into the corresponding wellbore 200.

Several different methods may be used for hydraulically fracturing the reservoir 206 via the well 100. For example, a hydraulic fracturing process referred to as a “plug-and-perforation process” may be used. 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 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.

As an alternative to perforating the production casing 212, the connection to the reservoir 206 could be created by downhole sleeves or rupture discs, which are activated by a variety of mechanisms not involving perforating. In some embodiments, this type of completion may be used in the well 100.

FIG. 3 is an illustration showing an example system 300 using an annulus injection unit 102, according to an exemplary embodiment of the present techniques. The system 300 includes a high pressure, low volume chemical injection pump, manifolding between the pump and a well's casing annulus, a pressure shutdown switch, and any number of tanks for storing any number of heavy brines on location.

The Christmas tree 301 includes a kill wing valve 302. The Christmas tree 301 includes a swab valve 304. The Christmas tree 301 also includes a production wing valve 306. The Christmas tree 301 includes an emergency shut down (ESD) valve 308. A manual choke 310 is attached to the outside of the ESD valve 308. The Christmas tree 301 includes an upper and lower master valve 312.

The Christmas tree 301 is connected to a wellhead 313. The wellhead 313 includes an inner and outer production casing valves 314. The inner and outer production casing valves 314 are connected to a production casing line 316. The wellhead 313 includes an intermediate casing valve 318. The wellhead 313 includes a production casing hanger 320 that sits inside the wellhead 313 to suspend the production casing. The wellhead 313 also includes a surface casing outlet 324.

The annulus injection unit 102 includes an isolation valve 326 fluidically coupled to intermediate casing valves 318 and 322. For example, the isolation valve 326 can be used to isolate the wellhead 313 from the annulus injection unit 102. In various embodiments, a line attached to the isolation valve 326 is used for injecting brine from the pump into the micro-annulus. For example, the line may be a ⅜″ stainless steel line.

The annulus injection unit 102 includes a tee 328 and annulus bleed off valve 330 fluidically coupled to the tee 326 and a flowline (not shown) of a well. In various embodiments, the annulus bleed off valve 330 is used to initiate and terminate bleeding off of liquids to reduce surface pressure at casing string annuli.

The injection system 300 includes an isolation valve 332 coupled to the tee 328. For example, the isolation valve 332 can be used to isolate the annulus injection unit 102 from the bleed down line. The isolation valve 332 may thus be used to isolate the annulus injection unit from the annulus when a bleed-down operation is performed to relieve a part of the surface pressure of the annulus before a brine is injected into the annulus.

The injection system 300 includes a check valve 334 fluidically coupled to the isolation valve 332. For example, the check valve 334 can be used to ensure that brine does not return back into the brine tank 336. In various embodiments, the check valve 334 is redundant to a check valve integral to the high-pressure, low-volume pump that injects the brine.

The injection system 300 includes a brine tank 336 coupled to the check valve 334. For example, the brine tank 336 can be used to store a brine, such as NaCl or NaBr. In various embodiments, the brine is also inhibited using various additives.

The injection system 300 includes a vent 338 coupled to the brine tank 336. For example, the vent 338 can be used to vent off vapors from the brine in the brine tank 336.

In various embodiments, the annulus injection unit 102 thus includes a high pressure, low volume chemical injection pump, manifolding between the pump and a well's casing annulus, a pressure shutdown switch, and any number of tanks 336 for storing any number of heavy brines on location.

In various embodiments, the pump is solar powered with battery backup. In some embodiments, based on the need for reliable comms and the availability of electrical supply at the initial installations, electrical power is used to send unit operating data to the cloud.

FIG. 4 is a detailed schematic illustration showing an example system 400 with an annulus injection unit 102 coupled via a surface manifold 402 to a casing string 404 of a single well 406, according to an exemplary embodiment of the present techniques. For example, the casing string 404 may have an associated micro-annulus 408 causing a surface pressure of the casing string 404 to exceed a threshold pressure, such as a pressure below MAWOP or any other threshold pressure. In various examples, the casing string 404 may be any intermediate or outer casing string that is not currently being intentionally injected to produce hydrocarbons nor currently being used to produce hydrocarbons. For example, such casing string 404 may be installed as part of the building of a well 406, and may serve as protection feature to contain pressure during the production life of the well 406. In various examples, the micro-annulus 408 may potentially have formed along any portion of the casing string 404, causing pressure buildup within the casing string 404. For example, the pressure buildup may be from fluids entering from a formation near a casing string shoe of the well 406. In some examples, the pressure buildup may be caused by hydrocarbons leaking from the fracked reservoir up the outside of the production casing into the intermediate by production casing annulus via the micro-annulus 408. As another example, a charged up aquifer may be feeding liquid to the surface by intermediate annulus via a micro-annulus 408. Thus, one of skill in the art will understand that the aspects of the present disclosure are not limited to any specific pressure source nor any specific type of intermediate or outer casing string.

In various embodiments, the annulus injection unit 102 includes a brine 410, such as an inhibited NaCl brine, NaBr, or a mixture thereof. The annulus injection unit 102 includes a pump 412 fluidically coupled to pump the brine 410 into the surface manifold 402. The annulus injection unit 102 further includes a pressure switch 414. For example, the pressure switch 414 may be set to a threshold shutoff pressure, such as a pressure below MAWOP, or any other suitable threshold shutoff pressure.

FIG. 5 is a schematic illustration showing an example system 500 with annulus injection unit coupled via a manifold 502 to one or more casing strings 404A, 404B, 404C, 404D of multiple wells 406A, 406B, 406C, and 406D, according to an exemplary embodiment of the present techniques. The system 500 leverages a single installation of an annulus injection unit 102 for multiple wells 406A-406D on a single well pad afflicted with micro-annuli 408A, 408B, 408C, and 408D and associated high casing surface pressures. For example, the pad may be a location prepared of caliche rock flattened in a levelled area around the wells to allow for access and set up of drilling rigs, workover rigs, pump trucks, operator access, etc. around the wells.

In various embodiments, the pump 412 injects the brine 410 into the manifold 502. One or more of the casings strings 404A-404D may have been bled down manually and may thus be injected with the brine 410 via the manifold 502 until a corresponding pressure switch 414A, 414B, 414C, or 414D disables further injection into each respective casing string 404A, 404B, 404C, or 404D. Thus, in the embodiment described in FIG. 5, if multiple wells 406A-406D on a path that have high surface pressures at one or more casing strings, then the most expensive component, which is the pump 412, can be leveraged across multiple wells 406A-406D on the path.

FIG. 6 is a process flow diagram of an exemplary method 600 for mitigating high annulus casing pressure on a well, according to the present techniques. At block 602, an annulus injection unit is attached to a casing string. For example, the annulus injection unit is attached to the casing string using a surface manifold that connects the annulus injection unit to one or more wells. In some embodiments, the annulus injection unit is tied into a monitoring system for real time monitoring via the cloud. For example, the monitoring system may be a Modbus 485/SCADA.

At block 604, annuli fluid volumes are periodically bled off. In various examples, the fluid volumes may primarily be gas. As one example, a well's intermediate casing pressure may have built up to an undesirably elevated pressure of about 2,100 psi. In various examples, the MAWOP of a casing string is calculated per API based on the specifications for the casing string having the micro-annulus and the calculation is also dependent on the specification of the casing (or tubing) strings inside and outside of the casing string being evaluated. During a site visit, an operator may thus perform a bleed down of the intermediate casing pressure to the well's flowline from ˜2,100 psi to within a range of 100-500 psi. In various embodiments, the bleed down may be performed once a day, or a few times a week. Moreover, depending on the specific well and the amount of pressure built up, each of the bleed downs may last from five to 20 minutes or more. In various embodiments, after the target pressure is reached, the bleed down is then terminated, and the operator closes valves to isolate the well's intermediate casing but leaves the well's intermediate casing pressure transmitter open to the well.

At block 606, a brine is injected into the casing string of the well to establish an initial injectivity into a micro-annulus of the casing string. In some embodiments, the brine is an inhibited brine. For example, the brine may be a solution of sodium chloride that is mixed with corrosion inhibitors and oxygen scavengers to form an inhibited brine. As one example, an operator opens valves to allow the annulus injection unit to inject, the pump is turned on, and the system attempts to inject inhibited 10 lb/gal NaCl brine into the well's annulus at rates adjustable from approximately 20-120 quarts per day. In various embodiments, at this time, the operator can leave the well, and allow the pressure switch to control the pump shut down. In some embodiments, the shutdown pressure switch, set at a value below the calculated MAWOP pressure for that well's casing string, shuts down injection of the inhibited brine below MAWOP. In various embodiments, injection data is captured using the SCADA monitoring device.

At block 608, a determination is made as to whether the surface pressure of the casing string is stabilizing below a target threshold pressure. For example, the determination may be made after a predetermined time or number of iterations of bleeding off and injection. In various examples, a well may take three to twelve months to stabilize below the target threshold pressure. If the surface pressure of the casing string is progressing towards stabilizing below a target threshold pressure, then the method 600 continues with additional iterations of bleed offs and injections at blocks 604 and 606. For example, blocks 604 and 606 may be repeated on subsequent well site visits and intermediate casing bleed downs. In various embodiments, injections can be repeated as necessary once the system has demonstrated success to maintain the casing string's pressure below the target pressure. In various examples, the target threshold pressure may be any other suitable pressure, such as 200 psi. If the surface pressure of the casing string is progressing towards stabilizing below a target threshold pressure, then the method 600 continues at block 610. If the surface pressure is not progressing towards a stable pressure under the target threshold pressure, then the method 600 continues at block 612. For example, the surface pressure may have stabilized at 1,000 psi using the inhibited 10 lb/gal NaCl brine, whereas the target threshold pressure is 200 psi.

At block 610, a determination is made as to whether the surface pressure has stabilized below the target threshold pressure. If the surface pressure has stabilized below the target threshold pressure, then the method 600 ends at block 614. If the surface pressure has not stabilized below the target threshold pressure, then the method 600 continues at block 604.

At block 612, a higher density brine is injected to replace bled off annuli fluid volumes and reduce the surface pressure of the casing string to a stable pressure below the target threshold. For example, blocks 604 and 606 may be repeated as necessary using the higher density brine until the determination at block 610 indicates that the surface pressure has stabilized below the target threshold pressure. In some examples, the higher density brine may be the same type of brine as the first brine. For example, the higher density brine may include the same salt as the first brine, but at a higher concentration. Using a higher concentration of the same salt can improve the compatibility of the first and second brines, avoiding undesirable precipitation of salts that may occur when mixing differing brines comprising differing salts. In various examples, the higher density brine may be a different type of brine. For example, in some embodiments, the higher density brine is sodium bromide solution, such as a 12.5 lb/gal NaBr or 1.5 gm/cm3 sodium bromide solution. In some embodiments, after some initial injectivity is achieved with a base fluid (i.e., 10 lb/gal NaCl or 1.2 gm/cm3), the density of this base fluid can be increased to a compatible, much heavier brine (i.e., 12.5 lb/gal NaBr or 1.5 gm/cm3) to further drive down and manage casing pressure. As one example, if the pressure switch is shutting down the pump such that it is apparent that the micro-annulus was filled with liquid and no gas, and the surface pressure is above the target pressure, then a switch is made to the injection of a higher density brine such as sodium bromide. In various embodiments, system success may take anywhere from one to 12 months or more to evaluate, depending on the rate of injection achieved, the extent of the bleed downs performed, and the frequency with which bleed downs and injections are done. In various examples, success is achieved when the long-term injection of heavy brine into a well's micro-annulus has reduced the casing string's surface pressure an elevated level to well below the calculated MAWOP pressure for a well's casing string. For example, the target pressure may be approximately 200 psi. In various embodiments, the annulus injection unit may become a permanent installation at the wellsite or may be moved to another location, depending on the success achieved and/or need at another well.

Those skilled in the art will appreciate that the exemplary method 600 of FIG. 6 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. 6 may be altered or omitted from the method 600 and/or new blocks may be added to the method 600. Moreover, in some embodiments, the method 600 is performed for multiple wells that are located in the same field as the well and/or in one or more adjacent fields.

FIG. 7 is a graph 700 showing a decrease in high casing pressure following injection of sodium bromide (NaBr) into example well in accordance with the present techniques. The graph 700 has an x-axis 702 representing time. A left y-axis 704 represents pressure at a wellhead of a treatment well. Prior to injection, the example well's intermediate casing was seen to be increasing towards a pressure approaching MAWOP despite periodic casing bleed downs being performed by the operator. Moreover, a zoom-in on one of this well's intermediate casing pressure bleed down and buildup cycles revealed that less than ˜5 hours would be available for injection of heavy brine into this well's annulus following a bleed down cycle. In other words, after dropping to below 500 psi the pressure with a bleed off, the well would again reach the pressure approaching MAWOP in approximately five hours. Following the commissioning of the annulus injection unit on the well, the intermediate casing pressure eventually decreased, achieving a minor pressure reduction while operating the unit. After this initial injection of sodium chloride, the brine was changed to increase the heavy brine density from NaCl (10 lbs/gal or 1.2 g·cm⁻³) to a compatible NaBr (12.5 lbs/gal or 1.5 g·cm⁻³). After swapping out the brine tank from NaCl (10 lbs/gal or 1.2 g·cm⁻³) to compatible NaBr (12.5 lbs/gal or 1.5 g·cm⁻³) brine, the annulus injection unit was turned on and after injecting the heavier brine for approximately one month, complete success was achieved. In particular, the pressure at the surface of the casing string stabilized within the range of 200-300 psi.

The data shown in the graph 700 accordingly depicts a condition in which an initial bleed off resulting in a pressure drop followed by a series of injections 706 of sodium bromide over a period of a month that resulted in a stable pressure 708 of around 200-300 psi. Thus, in accordance with aspects of the present disclosure, shortly after injection of a fluid containing sodium bromide into the treatment well, the fluid mixture of sodium bromide and sodium chloride caused a surface pressure of the casing string to drop to a stabilized lower pressure.

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.