Patent Application
20240376795
Wellbores are commonly drilled to enable the production of subterranean fluids such as hydrocarbons (e.g., oil and gas). A wellbore is formed using a drill bit at the lower end of a drill string. The drill bit is rotated while force is applied through the drill string and against the rock face of the formation being drilled. After drilling to a predetermined depth, the drill string and bit are removed, and the wellbore is lined with a string of casing. The casing string may provide a conduit for conveying produced subterranean fluids from one or more subterranean formations (e.g., reservoirs) to a surface location. Wellbore equipment, which may be placed in or connected to the wellbore may include one or more devices which either promote or impede the production of subterranean fluids from a subterranean formation to a surface location. For example, pumps may be utilized to convey subterranean fluids to a surface location, while production isolation devices may prevent the production of subterranean fluids. An annular area is thus formed between the string of casing and the formation penetrated by the wellbore.
A cementing operation is typically conducted to displace drilling fluid and fill part or all of the hollow-cylindrical annular area between the casing and the borehole wall with cement. The combination of cement and casing strengthens the wellbore and facilitates the zonal fluid isolation of certain sections of a hydrocarbon-producing formation (or “pay zones”) behind the casing. The first string of casing is placed from the surface and down to a first drilled depth. This casing is known as a surface casing. In the case of offshore operations, this casing may be referred to as a conductor pipe. Typically, one of the main functions of the initial string(s) of casing is to isolate and protect the shallower, usable water bearing aquifers from contamination by any other wellbore fluids. Accordingly, these casing strings are almost always cemented entirely back to surface. One or more intermediate strings of casing are also run into the wellbore. These casing strings will have progressively smaller outer diameters into the wellbore. In most current wellbore completion jobs, especially those involving so called unconventional formations where high-pressure hydraulic operations are conducted downhole, these casing strings may be entirely cemented. In some instances, an intermediate casing string may be a liner which is a string of casing that is not tied back to the surface.
The process of drilling and then cementing progressively smaller strings of casing is repeated several times until the well has reached total depth. In some instances, the final string of casing is also a liner. The final string of casing, referred to as a production casing, is also typically cemented into place. Additional tubular bodies may be included in a well completion. These include one or more strings of production tubing placed within the production casing or liner. Each tubing string extends from the surface to a designated depth proximate a production interval, or “pay zone.” Each tubing string may be attached to a packer. The packer serves to seal off the annular space between the production tubing string(s) and the surrounding casing.
Swellable packers are used in open hole and cased hole applications to support production equipment, set liners, set plugs, and in various other wellbore construction operations. Swellable packers typically include a swellable material disposed on a tubular where the swellable material swells on contact with a fluid, expanding to form an annular seal. The swellable material used to construct the packer may be sensitive to fluids present in the wellbore. For example, in wellbores where corrosive fluids are present such as acids, amines, hydrogen sulfide, and carbon dioxide, there may be additional considerations for the long-term integrity of the in-well equipment such as swellable packers. For instance, a swellable packer sheath which is exposed to a corrosive fluid may begin to uptake the corrosive fluid into the matrix of the swellable packer which may cause chemical and physical changes within the swellable packer. Swellable packers exposed to corrosive fluids may behave like a composite material with spatially varying mechanical properties. Fluids and gases in the reservoir may change the volume of the swellable packer, which may compromise the ability of the swellable packer to provide zonal isolation.
These drawings illustrate certain aspects of some of the embodiments of the present disclosure and should not be used to limit or define the method.
The present disclosure may generally relate to swellable packers and methods of deploying swellable packers in wellbore. More particularly, the present disclosure relates to swellable packers comprising a protective material covering at least partially a swellable material with enhanced protection against chemical and physical changes once the swellable packer is deployed in a wellbore. The swellable material is disposed on the tubular of the wellbore packer assembly and may swell upon contact with a swelling fluid or a material changing fluid such as a downhole fluid (i.e., oil, gas, brine, carbon dioxide, and any combination thereof). The swelling of the swellable material expands the protective material against the wellbore wall forming a seal.
Wellbore 106 may extend through the various earth strata including subterranean earth formation 108. Wellbore 106 may be drilled according to a wellbore plan to reach one or more target formations, to avoid non-desirable formation features, to minimize footprint of the well at the surface, and to achieve any other objectives for the well. Wellbore 106 may follow a chosen path (i.e., the wellbore path) from where the wellbore 106 initiated at the earth's surface 104 (i.e., the “heel”) to the end of the well 118 (i.e., the “toe”). The initial portion of wellbore 106 is typically vertically downward as the drill string would generally be suspended vertically from rig 102. Thereafter, wellbore 106 may deviate in any direction as measured by azimuth or inclination, which may result in sections that are vertical, horizontal, angled up or down, and/or curved. The term uphole generally refers to a direction along the wellbore path toward the earth's surface 104 and the term downhole generally refers to a direction toward the toe at the end of the well 118, without regard to whether a feature is vertically upward or vertically downward with respect to a reference point. The wellbore path in
Wellbore 106 may be at least partially cased with a casing string 116 at selected locations within the wellbore 106, while other portions of wellbore 106 may remain uncased. The casing string 116 may be secured within wellbore 106 using cement. In other embodiments, the casing string 116 may be only partially cemented within wellbore 106 or, alternatively, the casing string 116 may be entirely un-cemented. Casing string 116 may be made from any material such as metals, plastics, composites, or the like, may be expanded or unexpanded as part of an installation procedure. Production tubing may be any suitable tubing string utilized in the production of hydrocarbons. In examples, production tubing may be permanently disposed within casing string 116. The packers 120a, 120b, may be disposed on or near production tubing.
Rig 102 may include a hoisting apparatus for raising and lowering equipment from derrick 110 on conveyance 114. Conveyance 114 may serve various functions, such as to lower and retrieve tools, to convey fluids, and to support electrical communication, power, and fluid transmission during wellbore operations. Conveyance 114 may include any suitable equipment for mechanically conveying tools such as the packers 120a, 120b, and any suitable packer setting assembly for setting the packers 120a, 120b. Such conveyance may include, for example, a tubular string made up of interconnected tubing segments, or wireline, slickline, coiled tubing, or any combination of any of the foregoing. In some examples, conveyance 114 may provide mechanical suspension, as well as electrical and fluidic connectivity, for downhole tools like the packers 120a, 120b. Conveyance 114 may be used to lower one or more tools into wellbore 106, i.e. run/tripped into the hole. When a wellbore operation is complete, or when it becomes necessary to exchange or replace tools or components of conveyance 114, conveyance 114 may be raised or fully removed from wellbore 106, i.e., tripped out of the hole. The packers 120a, 120b are examples of downhole tools that may be deployed on conveyance 114. The packers 120a, 120b may be actuated at selected locations to seal off a portion of wellbore 106.
One or more packers or other sealing tools according to this disclosure may be set for any of a variety of sealing purposes. As depicted in
A variety of packer types may be utilized according to this disclosure, including but not limited to production packers and service packers. Suitable types of packers may include whether they are permanently set or retrievable, mechanically set, hydraulically set, and/or any combinations thereof. As just one example, the packers 120a and/or 120b may be production packers that will remain in the well during well production. Alternatively, the packers 120a and/or 120b may be service packers used temporarily during well servicing, such as cementing, acidizing, or fracturing. When set, packer 120 may isolate zones of the annulus between wellbore 106 and a tubing string by providing a seal between production tubing and casing string 116. In examples, a packer may be disposed on production tubing. Downhole setting tools may also be disposed on conveyance 114 and run into wellbore 106 for actuating the packers 120a, 120b.
To achieve high element expansion and a high-pressure sealing system with minimal hydraulic setting force, the sealing element may be deployed outwardly by expanding it over a dual prop and piston arrangement. A pair of opposing props 236, 238 are radially disposed between an outside diameter (OD) of mandrel 222 and the shroud 224. The props 236, 238 are axially moveable toward one another to selectively engage the sealing element 240 in order to urge the scaling element 240 outwardly through the gland opening 230 into scaling engagement with an inner diameter (ID) of the casing 216.
Over the life of an oil and gas well, production of reservoir fluids depletes the reservoir leaving behind a volume which may be used to store carbon dioxide, i.e. a carbon dioxide injection zone. The carbon dioxide injection zone can include subterranean formations where hydrocarbons were produced and depleted from. These depleted wells can be utilized to store carbon dioxide (CO2) by injecting carbon dioxide into the carbon dioxide injection zone to transform the depleted well to a carbon capture underground storage (CCUS) well. As discussed above, swellable packers are utilized in construction of the wellbore and therefore when a depleted well is converted to a CCUS well, the swellable packers may be exposed to carbon dioxide. In some embodiments, differential pressure across the swellable packer is reduced by placing a fluid above the packer. For example, the swellable packers of the present disclosure can be exposed to carbon dioxide and water or a benign fluid as the benign fluid is injected into the upper stratum above the carbon dioxide injection layer and its cap-rock to reduce the upward leakage rates of carbon dioxide during and after its injection.
Turning now to
However, carbon dioxide is a corrosive fluid which can change the properties of a swellable packer. Furthermore, the operational conditions in which the carbon dioxide (CO2) is introduced into the wellbore such as temperature, pressure, and state of the CO2 such as gaseous CO2, liquid (supercritical) CO2, or CO2 dissolved in water (carbonic), each can affect the extent of carbonation of the swellable packer. The swellable packer of the present disclosure including the protective material covering at least partially the swellable material may be utilized in any wellbore type, including wellbore environments which contain carbon dioxide, where the swellable packer of the present disclosure may have extended life as compared to conventional swellable packers. The swellable packer of the present disclosure may be utilized in wellbores where corrosive fluids are present, including, but not limited to, acids, amines, and hydrogen sulfide where the swellable packer including the protective material covering at least partially the swellable material may have extended life as compared to conventional swellable packers. Therefore, the swellable packer of the present disclosure may be used for CO2 injection well, secondary oil recovery, enhanced oil recovery, or any wellbore treatment, for example.
The swellable packers of the present disclosure include a protective material covering at least partially a swellable material with enhanced protection against chemical and physical changes once the swellable packer is deployed in a wellbore. The protective material may be any material that can protect the swellable material including metals, polymers, ceramics, composites, and any combination thereof. The protective metal may be any pure metal or any alloy capable of enhanced protection against the downhole environment including any ferrous alloys, for example. The protective metal may be in the form of a metallic flap that is displaced upon expansion of the swellable material, for example. The protective polymer may be any polymeric material capable of enhanced protection against the downhole environment including any elastomer, thermoset, and thermoplastic such as styrene butadiene, natural rubber, ethylene propylene monomer rubber, ethylene propylene diene monomer rubber, ethylene vinyl acetate rubber, hydrogenated acrylonitrile-butadiene rubber, acrylonitrile butadiene rubber, isoprene rubber, chloroprene rubber, polynorbornene, EPDM, nitrile rubber, HMBR, acrylonitrile, hydrogenated nitrile, chloroprene, ethylene vinylacetate rubber, silicone, ethylene propylene diene monomer, butyl, chlorosulphonated polyethylene, polyurethane, ACM, BIMS, and any combinations thereof. The protective ceramic may be any ceramic material capable of enhanced protection against the downhole environment including any traditional ceramic or any engineered ceramic. The protective composite may be any composite material capable of enhanced protection against the downhole environment including metal matrix composite, polymer matrix composite, or ceramic matrix composite.
The protective material may be swellable or non-swellable in presence of material changing fluid such as oil, gas, brine, carbon dioxide, acid, cement, and any combination thereof. Non-swellable protective materials include metals and polymers such as Teflon and hydrogenated nitrile butadiene rubber (HNBR), for example. Swellable protective materials include polymers such as ethylene propylene diene monomer rubber (EPDM), for example.
The protective material may be bonded with the swellable material to form a single structure. In embodiments, the bond is formed by a suitable method including but not limited to a mechanical method such as clamping the protective material and the swellable material together, pressing fitting the protective material against the swellable material, thermally bonding the protective material and the swellable material such as by contacting and heating the protective material and swellable material together, and/or a chemical method including utilizing a polymerization additive to form a polymer bond (e.g. vulcanization) or using a glue.
Reference is made to
In
Protective element 506 and packer element 504 may be any elastomeric sleeve, ring, or band suitable for creating a fluid tight seal with tube 502 and an outer tubing, casing, or wellbore in which tube 502 is disposed. The packer assembly 500 may be any material and have any shape and size. In certain embodiments, the packer assembly 500 may be designed for the conditions anticipated at each selected interval in which the isolation packer assembly 500 is being used, taking into account the expected temperatures and pressures, for example. In certain embodiments, only a portion of the packer assembly 500 such as packer element 504 may comprise a swellable material.
The packer element 504 has several advantages. For example, by layering a relatively less swelling material or a non-swelling material on top of a relatively more swelling material, the differential swelling of the packer element 504 causes the protective element 506 to be pushed against the borehole wall, either casing or open hole inner diameter, which creates a seal between the less swelling material and the borehole wall. The seal then further protects the packer element 504 from subsequent fluid exposures. In the example of the CO2 storage wells of
Accordingly, the present disclosure may provide wellbore packer assemblies and methods of use of these wellbore packer assemblies which include a protective material, a swellable material, and a tubular. The methods and systems may include any of the various features disclosed herein, including one or more of the following statements.
It should be understood that the compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces.
For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.
Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular examples disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual examples are discussed, the disclosure covers all combinations of all those examples. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative examples disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.
The present application claims priority to U.S. Provisional Application No. 63/501,589, filed May 11, 2023, the entire disclosure of which is incorporated herein by reference.
| Number | Date | Country | |
|---|---|---|---|
| 63501589 | May 2023 | US |
