Toe flap valve for internal corrosion prevention in ccus injection well tubing

Abstract

An apparatus and method for internal corrosion prevention is used for carbon capture utilization and storage injection well tubing. The method is directed to control flow in an injection well tubing and preventing internal corrosion of the injection well tubing. The method comprises steps of injecting CO2 stream into a hydrocarbon bearing reservoir from an injection well; and using a flap valve at a bottom end of an injection well tubing that operates by responding to elevated injection pressures; and automatically closing upon injection cessation, effectively preventing a flow-back of formulation fluids into the injection well tubing.

Description

[0001] Patent CU-75505-CNPC USA FYG TOE FLAP VALVE FOR INTERNAL CORROSION PREVENTION IN CCUS INJECTION WELL TUBING

[0002] CROSS REFERENCE TO RELATED APPLICATIONS

[0003]

[0001] This PCT application claims priority of a US Patent Application No. 18 / 966,046, filed on Dec. 02, 2024 (our docket No. CU-76341-CNPC-FYG), hereby incorporated by reference in its entireties.

[0004] Field of the Invention

[0005]

[0002] The present invention relates to a valve for a downhole pipe in the oil and gas industry and method of preventing internal corrosion. More particularly, the present invention relates to a toe flap valve for internal corrosion prevention in carbon capture utilization storage (CCUS) injection well tubing and a method of preventing internal corrosion in carbon capture utilization and storage injection well tubing and storing CO2 in a hydrocarbon reservoir.

[0006] Background

[0007]

[0003] Carbon Capture and Storage (CCS) technology has gained widespread acceptance and recognition as an effective tool in global carbon reduction initiatives. It stands as an essential technique to fulfill the goals outlined in the Paris Agreement. Nonetheless, the adoption of CCS has been hindered by its gradual implementation, largely attributed to its elevated expenses. Despite the presence of government incentives like the 45Q tax policy, the high costs persist. A notable contributor to these costs is the necessity of employing costly corrosion-resistant alloys for downhole tubing and tools. This requirement arises from the challenging downhole corrosion environment. For instance, the newly published AMPP Guide 21532-2023 recommends the use of the pricey 25Cr alloy. Consequently, any innovation capable of economizing material selection holds the potential to significantly enhance the global implementation of CCS technology.

[0008]

[0004] In actuality, the injected CO2 stream does not exhibit corrosive properties, even in the presence of significant corrosive impurities. This is due to the fact that these gases do not cause metal corrosion in the absence of free water. Additionally, the CO2 stream undergoes through dehydration prior to transportation through carbon steel CO2 pipelines. In simpler terms, the challenge within the injection well stems not from the CO2 stream itself, but rather from the interaction between this stream and the water phase present within the reservoir.

[0009]

[0005] Therefore, there is a need to have an apparatus for internal corrosion prevention in carbon capture utilization and storage injection well tubing.

[0010]

[0006] These and other objectives and advantages of the present invention will become apparent from a reading of the attached specification.

[0011] BRIEF SUMMARY OF THE INVENTION

[0012]

[0007] Embodiments of the present invention include an apparatus for internal corrosion prevention in carbon capture utilization and storage injection well tubing. The apparatus comprises a flap valve at a bottom end of the injection well tubing that operates by responding to Patent CU-75505-CNPC USA FYG elevated injection pressures and automatically closes upon injection cessation, effectively preventing a flow-back of formulation fluids into the injection well tubing.

[0013]

[0008] Optionally in any embodiment, the flap valve is rotatable between open and closed positions for controlling the flow in the injection well tubing.

[0014]

[0009] Optionally in any embodiment, the flap valve comprises a flapper hinge about which the flap valve rotates.

[0015]

[0010] Optionally in any embodiment, the flap valve comprises a valve seat to hold pressure exerted on an upstream flap valve face in the closed position.

[0016]

[0011] Optionally in any embodiment, the flap valve comprises a hinge pin formed on said flap valve.

[0017]

[0012] Optionally in any embodiment, the flap valve comprises a torsion spring means being loaded in torsion as the flap valve rotates from the closed position to the open position to exert a restoring force for rotating the valve flapper to the closed position.

[0018]

[0013] Optionally in any embodiment, the torsion spring means has one end connects and biases on an outer surface of the flap valve, while the other end connects and biases on the outer surface of the injection well tubing.

[0019]

[0014] Optionally in any embodiment, the torsion spring means has both ends that connect and bias on the outer surface of the injection well tubing.

[0020]

[0015] In another embodiment, a valve may be used in controlling flow in an injection well tubing. The injection well tubing may have a first end and a second end in a downhole injection well tubing. The valve may comprise a flap valve having a torsion spring means with one end connecting and biasing on an outer surface of the flap valve, while the other end connects and biases on the outer surface of the injection well tubing, wherein the flap valve comprises a valve seat to hold pressure exerted on an outer surface of the flap valve in the closed position, wherein area that the valve seat covers is substantially the same as the area of the inner diameter of injection well tubing.

[0021]

[0016] Optionally in any embodiment, the flap valve is rotatable to open and close the bore of the injection well tubing at the second end of the injection well tubing while the first end of the injection well is located at the surface of land.

[0022]

[0017] Optionally in any embodiment, the flap valve comprises a flapper hinge about which the flap valve rotates.

[0023]

[0018] Optionally in any embodiment, the flap valve comprises a valve seat to hold pressure exerted on an outer surface of the flap valve in the closed position.

[0024]

[0019] Optionally in any embodiment, the flapper hinge comprises a hinge pin formed on said flap valve.

[0025]

[0020] Optionally in any embodiment, the torsion spring means is secured to the hinge pin.

[0026]

[0021] Optionally in any embodiment, the torsion spring means is loaded in torsion as the flap valve rotates from the closed position to the open position to exert a restoring force for rotating the valve flapper to the closed position.

[0027]

[0022] Optionally in any embodiment, the spring means comprises a coil spring, rotation of said flap valve about an axis of rotation to open said flapper loading said springs in torsion.

[0028]

[0023] In further embodiment, a flap valve for internal corrosion prevention in CCUS injection well tubing, comprises a flap that moves into contact with the tubing to create a tight seal Patent CU-75505-CNPC USA FYG when the injection pressure is above a certain threshold; and a spring means comprising a coil spring, rotation of said flap valve about an axis of rotation to open said flap loading said spring means in torsion, a valve flapper rotatable between open and closed positions for controlling the flow in the fluid transmission conduit, wherein the flap valve's operation neither constrains the injection flow rate nor induces the Joule-Thomson effect.

[0029]

[0024] Optionally in any embodiment, the torsion spring means comprises a coil springs, rotation of said valve flapper about said axis of rotation to open said flap loading said springs in torsion.

[0030]

[0025] Optionally in any embodiment, the torsion spring means has one end connects and biases on an outer surface of the flap valve, while the other end connects and biases on the outer surface of the injection well tubing.

[0031]

[0026] Optionally in any embodiment, the torsion spring means has both ends connects and biases on the outer surface of the injection well tubing.

[0032]

[0027] In further embodiment, a method of preventing internal corrosion in carbon capture utilization and storage injection well tubing and storing CO2 in a hydrocarbon reservoir having at least one injection well. The method may comprise steps of importing a CO2 stream to an injection facility wherein the imported CO2 is either in a liquid state or a supercritical state; injecting the CO2 stream into the hydrocarbon bearing reservoir from said injection well; using a flap valve at a bottom end of an injection well tubing that operates by responding to elevated injection pressures and automatically closes upon injection cessation, effectively preventing a flow-back of fluids into the injection well tubing; continuing injecting the CO2 stream into the hydrocarbon bearing reservoir; and pushing the flap valve open through the pressure of the liquid CO2 stream into the hydrocarbon bearing reservoir.

[0033]

[0028] In yet further embodiment, a method for controlling flow in an injection well tubing and preventing internal corrosion of the injection well tubing may comprise steps of injecting CO₂ stream into a hydrocarbon bearing reservoir from an injection well; and using a flap valve at a bottom end of an injection well tubing that operates by responding to elevated injection pressures; and automatically closing upon injection cessation, effectively preventing a flow-back of fluids into the injection well tubing.

[0034]

[0029] Optionally in any embodiment, the flap valve is configured to achieve gas tight seal, and keep the sealing performance with large temperature cycle from -80°C to 150°C in short period of time (1-20 mins), for example.

[0035]

[0030] In still further embodiment, a method of preventing internal corrosion in carbon capture utilization and storage injection well tubing and storing CO2 in a hydrocarbon reservoir having at least one injection well may comprise steps of injecting the CO2 stream into the hydrocarbon bearing reservoir from said injection well; using a flap valve in contact with the tubing to create a tight seal when the injection pressure is below a certain threshold, wherein the flap valve comprises: torsion spring means comprising a coil spring, rotation of said flap valve about an axis of rotation to open said flap loading said spring means in torsion, a valve flapper rotatable between open and closed positions for controlling the flow in the fluid transmission conduit, wherein the flap valve's operation neither constrains the injection flow rate nor induces the Joule-Thomson effect, wherein the flap valve is configured to achieve gas tight seal, and keep the sealing performance with large temperature cycle from -80°C to 150°C in short period of time (1-20 mins). Patent CU-75505-CNPC USA FYG

[0036] BRIEF DESCRIPTION OF DRAWINGS

[0037]

[0031] FIG. 1 is a perspective view of a flap valve according to one exemplary embodiment.

[0038]

[0032] FIG. 2 is a perspective view of a flap valve according to another exemplary embodiment.

[0039] DETAILED DESCRIPTION OF THE INVENTION

[0040]

[0033] Before the description of the embodiment, terminology, methodology, systems, and materials are described; it is to be understood that this disclosure is not limited to the particular terminologies, methodologies, systems, and materials described, as these may vary. It is also to be understood that the terminology used in the description is for the purpose of describing the particular versions of embodiments only, and is not intended to limit the scope of embodiments. For example, as used herein, the singular forms “a,” “an,” and “the” include plural references unless the context clearly dictates otherwise. In addition, the word “comprising” as used herein is intended to mean “including but not limited to.” Unless defined otherwise, all technical and scientific terms used herein have the same meanings as commonly understood by one of ordinary skill in the art.

[0041]

[0034] Unless otherwise indicated, all numbers expressing quantities of ingredients, properties such as size, weight, reaction conditions and so forth used in the specification and claims are to the understood as being modified in all instances by the term “about”.

[0042]

[0035] Accordingly, unless indicated to the contrary, the numerical parameters set forth in the following specification and attached claims are approximations that may vary depending upon the desired properties sought to be obtained by the invention. At the very least, and not as an attempt to limit the application of the doctrine of equivalents to the scope of the claims, each numerical parameter should at least be construed in light of the number of reported significant digits and by applying ordinary rounding techniques.

[0043]

[0036] As used herein, the term “about” means plus or minus 10% of the numerical value of the number with which it is being used. Therefore, about 50% means in the range of 45%-55%.

[0044]

[0037] The term “dense phase state” refers to a multi-component composition that has no definite volume or interface characteristics. Accordingly, a dense phase state fluid behaves similarly to a gas in that it will expand to fill a container in which it is placed. However, a dense phase fluid will have physical properties similar to those of a liquid. In particular, a dense phase fluid will have a density similar to that of a liquid. Accordingly, a dense phase fluid may be pumped to a higher pressure and a column of a dense phase fluid in an injection well will have a significant static head. Further, the dense phase CO₂ is a state that has a large number of moles of CO₂ per unit volume. Also, as there are no interface characteristics, it is implicit that a dense phase fluid will be single phase.

[0045]

[0038] The “cricondenbar” for a multi-component composition is the highest pressure at which two phases can coexist. Thus, where the pressure is above the cricondenbar, a multi¬ component composition cannot be two-phase (both liquid and vapour).

[0046]

[0039] The “cricondentherm” for a multi-component composition is the highest temperature at which two phases can co-exist. Patent CU-75505-CNPC USA FYG

[0040] The "critical point" for a multi-component composition is an experimentally determinable point and is the point (temperature and pressure) on the phase diagram where the mixture properties in the vapor phase and the liquid phase are the same.

[0047]

[0041] The terms “critical point", “cricondentherm” and “cricondenbar” as used herein, refer to the composition of the stream under discussion.

[0048]

[0042] The hydrocarbon reservoir may be an oil reservoir or a gas condensate reservoir and is any geological structure, strata, oil sand, reservoir rock etc. in which oil or gas condensate has naturally accumulated. Preferably, a plurality of injection wells penetrate the hydrocarbon reservoir. Preferably, a plurality of production wells penetrate the hydrocarbon reservoir.

[0049]

[0043] Preferably, the hydrocarbon reservoir is a reservoir of an oil field. Typically, the oil field may have more than one oil reservoir. Generally, to effectively and economically store CO2 in an oil field, the field should be large enough to have original oil in place of more than five million barrels. Preferably, the oil field should be in an area with an existing infrastructure of distribution pipelines that may be used for delivery of the imported CO2 stream. Typically, the oil field should have an injection facility and injection pipelines for a plurality of injection wells.

[0050]

[0044] The method of the present invention is particularly beneficial where an existing oil field is nearing the end of its production life (a depleted oil field). At the time that recovery of the produced fluid stream comprising produced hydrocarbons, produced water (connate water and any previously injected water) and produced COs from the production well ceases, injection of the injection stream will also cease and the emplaced volume of CO2 will be sequestered. Production of hydrocarbons and water from the oil reservoir, during injection of the injection stream, is essential to create space for the CO2 that is to be stored in the reservoir. If there was no production of hydrocarbons and water from the oil reservoir, the reservoir pressure would build up to the original reservoir pressure over a relatively short period of time, for example, 2 to 5 years, and the amount of CO₂ that can be sequestered is consequently reduced.

[0051]

[0045] The imported CO₂ stream preferably comprises at least 98% CO₂ on a dry basis. Thus, the imported CO₂ stream may comprise trace amounts of additional components selected from hydrogen, carbon monoxide, nitrogen and mixtures thereof. For example, where the imported CO₂ stream is obtained from a hydrogen plant, the additional components are mostly hydrogen and carbon monoxide. Typically, the amount of hydrogen in the imported CO₂ stream is less than 1% by weight.

[0052]

[0046] Although the imported CO2 stream is not a single component stream, the amount of impurities in the imported CO2 stream is so low that the phase behavior of this stream is similar to that of pure CO2. Accordingly, the imported CCkmay be regarded as being either in a liquid or a supercritical state. By "supercritical state” is meant that the imported GO has a pressure above the critical pressure for pure CChand a temperature above the critical temperature for pure CO2. Thus, compressing pure CCkat a temperature just below its critical temperature of 31.1° C. liquefies the gas at a pressure of approximately 73.8 bar (7.4 MPa) absolute. However, compressing CO2 at or above its critical temperature and critical pressure increases its density to a liquid-like stale but does not effect a phase change. At or above the critical point. CO2 is termed a supercritical fluid. Although supercritical CO2 can be compressed to a range of liquid like densities and can therefore be pumped, it retains the diffusivity of a gas and will expand to fill a container in which it is placed. Patent CU-75505-CNPC USA FYG

[0047] The imported CO2 stream is preferably sent by pipeline to the injection facility. The pipeline may be an existing gas export pipeline that has been switched to importing the CO2 stream to the injection facility. Where the imported CO2 stream arrives by pipeline, the CO is generally at ambient temperature, which in the case of a subsea pipeline will be the average temperature of the seabed (2 to 7° C., for example 4 to 6° C.). The pressure of the CO₂ that is flowing through the pipeline is preferably in the range of 75 to 250 bar (7.5 to 25 MPa) absolute, preferably, 100 to 200 bar (10 to 20 MPa) absolute. Thus, the pressure of the imported CO₂ stream will be above the cricondenbar for all compositions of the injection stream (irrespective of the molecular fraction of CO₂ in the injection stream). It is envisaged that the imported CO₂ stream may arrive by pipeline at the desired well-head pressure for the injection stream. Alternatively, the pipeline pressure of the imported CO2 stream may be below the desired well-head pressure for the injection stream. Accordingly, the pressure of the imported CO2 stream may be boosted to the desired well-head pressure prior to being mixed with the cooled stream in step. However, it is preferred to mix the imported CO2 stream with the cooled stream at the arrival pressure of the imported CO? stream and then subsequently boost the pressure of the injection stream to the desired well-head pressure. Typically, the imported CO₂ will be delivered by pipeline to the injection facility at a rate of at least 5000 tonnes per day (5 million kg per day), preferably, at least 5,500 tonnes / day (5.5 million kg per day). 5,500 tonnes / day equates to a CO₂ injection rate of 36 million reservoir barrels per day (mrbd) at typical bottom-hole conditions of a pressure of 7500 psi (52 MPa) and a temperature of 25° C.

[0053]

[0048] It is also envisaged that the imported CO2 may be delivered to the injection facility by tanker (road, rail or ship). Where the COsis transported to the injection facility by tanker, the CO2 will generally be in a liquid state. The tanker typically comprises a pressurized container for the liquid COa, a cargo discharge pump within said container for pumping the COsOut of the container along a conduit to the injection facility (thereby providing the imported CO2 stream). Typically, an external booster pump is also provided for pumping the imported CO2 stream to the injection facility. The CC hat is transported by tanker is generally refrigerated otherwise the pressures required to maintain the CC dn the liquid state are high making the required wall thicknesses of the pressurized containers high and therefore prohibitively expensive. Typically, for large scale transportation of COby tanker, the optimum temperature for the liquid state COjwill be in the range of -55 to -48° C., preferably -57 to -40° G.; and the pressure will be 5.2 to 10 bar (0.52 to 1 MPa) absolute, preferably, 5.5 to 7.5 bar (0.55 to 0.75 MPa) absolute. This corresponds to the position in the phase diagram for pure CO2 which is just above the triple point in terms of temperature and pressure. The triple point for pure CO2 is 5.2 bar (0.52 MPa) absolute and -56.6 G. Typically, the imported CO? stream is pumped to a pressure of 30 to 70 bar (3 to 7 MPa) absolute as it leaves the storage container, corresponding to a temperature of -50 to 0° C. The imported CO2 stream may then be pumped to the desired well-head pressure before being mixed with the cooled stream in step thereby forming the injection stream. Alternatively, the imported CO2 stream may be mixed with the cooled stream in a step at below the desired well¬ head pressure but at a pressure above the cricondenbar for the injection stream. The injection stream is then boosted to the desired well-head pressure. Transportation of CO2 in a liquid state via tanker at sub-ambient temperatures is expensive since refrigeration is required. Also, there is a risk that refrigeration of the CC^may result in the formation of solid CO2. Accordingly, transportation by pipeline is preferred. Patent CU-75505-CNPC USA FYG

[0049] As is well known to the person skilled in the art, the average pressure of a hydrocarbon reservoir (and hence the required down-hole pressure for injecting the injection stream into the hydrocarbon reservoir) varies depending upon the depth of the reservoir and the type of rock, among other things. For example, the down-hole pressure will be higher, the deeper the hydrocarbon reservoir. Generally stated, the average pressure of the hydrocarbon reservoir is controlled by the pressure on the injection well and the pressure of the production well. Generally, the down-hole pressure in the injection well is at least 200 psi (1.4 MF’a) above the average pressure of the hydrocarbon reservoir, for example, 200 to 500 psi (1.4 to 3.4 MF3a) above the average pressure of the hydrocarbon reservoir thereby ensuring that the injection stream is injected into the reservoir. However, certain reservoirs exhibit thermal fracturing behaviour where injectivity of a fluid into a reservoir increases when the pressure of the injection fluid is above a fracture opening pressure. Thus, fractures in the reservoir open and close depending upon the injection pressure. Accordingly, it may be necessary to increase the injection pressure of the injection stream to above the fracture opening pressure which may be at least 500 psi (3.4 MPa) higher, for example, at least 800 psi (5.5 MPa) higher than the average reservoir pressure.

[0054]

[0050] As is well known to the person skilled in the art, the average pressure of a hydrocarbon reservoir (and hence the required down-hole pressure for injecting the injection stream into the hydrocarbon reservoir) varies depending upon the depth of the reservoir and the type of rock, among other things. For example, the down-hole pressure will be higher, the deeper the hydrocarbon reservoir. Generally stated, the average pressure of the hydrocarbon reservoir is controlled by the pressure on the injection well and the pressure of the production well. Generally, the down-hole pressure in the injection well is at least 200 psi (1.4 MPa) above the average pressure of the hydrocarbon reservoir, for example, 200 to 500 psi (1.4 to 3.4 MPa) above the average pressure of the hydrocarbon reservoir thereby ensuring that the injection stream is injected into the reservoir. However, certain reservoirs exhibit thermal fracturing behaviour where injectivity of a fluid into a reservoir increases when the pressure of the injection fluid is above a fracture opening pressure. Thus, fractures in the reservoir open and close depending upon the injection pressure. Accordingly, it may be necessary to increase the injection pressure of the injection stream to above the fracture opening pressure which may be at least 500 psi (3.4 MPa) higher, for example, at least 800 psi (5.5 MPa) higher than the average reservoir pressure.

[0055]

[0051] As rioted previously, it is generally desired, as far as possible, that the injection stream is introduced into the reservoir at a significant distance from any production well to minimize the transport of the injected CO₂ to the production well. The ability to maximize the distance of the injection of the injection stream from any production well may depend on the structure and location of the hydrocarbon reservoir, and in particular the number and arrangement of injection and production wells. In general, the most effective storage of CO₂ is achieved by injecting the injection stream using an injection well at the flanks of a reservoir (the periphery). Where a hydrocarbon reservoir is not flat-lying the injection well preferably introduces the injection stream into a low-lying point of the reservoir, for example the base, of the reservoir (“downdip”).

[0056]

[0052] On land-based hydrocarbon reservoirs an arrangement of production and injection wells is commonly employed in oil production, for example a geometric arrangement Patent CU-75505-CNPC USA FYG known as a “pattern flood” where a plurality of production and injection wells are provided such that each production well has as its nearest neighbors a plurality of injection wells, and vice versa. For example, a production well may be serviced by six injection wells arranged in an approximately hexagonal configuration about the production well. Each injection well may have, as its nearest neighbors, three production wells. This configuration may be repeated across the hydrocarbon reservoir for the number of production wells required. In such a configuration, using an injection well for injecting the injection stream that is not surrounded by production wells is preferable, for example one located at the edge of the arrangement, such that not all of the CO2 injected in the injection stream flows towards production wells. Further improvements when injecting the injection stream into injection wells which are part of a pattern flood may be achieved by shutting in wells (both injection and production wells) to optimize the CO2 storage by maximizing the reservoir volume between an injection well and production well.

[0057]

[0053] For off-shore hydrocarbon reservoirs there are generally far fewer injection wells owing to drilling costs, so the operator may have less flexibility, but again it will generally be best to inject the injection stream into the periphery of the reservoir (as far as possible), and preferably at a low point of the reservoir, to maximize the distance between the injection well and the production well.

[0058]

[0054] Preferably, the CO₂ will be stored in the reservoir for at least 1000 years. Accordingly, the down-hole pressure of the injection stream should be such that the pressure in the reservoir does not exceed the reservoir overburden pressure. A pressure greater than the reservoir overburden pressure would result In the cracking and rupturing of the reservoir, and In the consequent leakage of CO2. Accordingly, CO2 could no longer be stored long-term in the reservoir. Towards the end of the life of the hydrocarbon reservoir, it may be preferred to reduce the pressure in the reservoir to below the original reservoir pressure before the injection and production wells are capped. This reduces the risk of the stored CO2 being released to the environment if one of the caps was to fail. Thus, fluids from surrounding formations will invade the reservoir and will hold the CO2 in place in the reservoir.

[0059]

[0055] The compressed stream is cooled to remove heat of compression thereby forming a cooled stream that is in a dense phase state. Typically, the compressed stream is cooled against a coolant in a heat exchanger, for example, against water. It is essential that the pressure is maintained at above the cricondenbar during this cooling step so as to avoid the risk of forming a two phase composition. Preferably, the compressed stream is cooled without any substantial reduction in its pressure. However, a pressure drop of up to 5 bar (0.5 MPa), preferably, up to 3 bar (0.3 MPa), may be tolerated provided that the pressure remains above the cricondenbar.

[0060]

[0056] As discussed above, the temperature of the imported CO2 stream, when delivered by subsea pipeline, is in the range of 2 to 7° C. Accordingly, the temperature of the injection stream will be intermediate between the temperature of the imported CO2 stream and the temperature of the cooled stream. Typically, the temperature of the injection stream will be within the range of 5 to 15° C., for example, 12 to 15° C., depending upon the amount of compressed and cooled stream that is mixed with the Imported CO2 stream. It is observed that the ratio of the cooled stream to imported CO2 stream will increase with time owing to increasing amounts of injected CO2 being produced from the hydrocarbon reservoir thereby resulting in increasing amounts of produced vapor stream that must be recycled to the reservoir. Typically, the two streams are mixed to form the injection stream in a ratio such that the mole % of CO2 in Patent CU-75505-CNPC USA FYG the injection stream is at least 70 mole %, preferably, at least 80 mole %, more preferably, at least 85 mole %. Typically, the cooled stream is mixed with the imported COaStream to form the injection stream at a rate of 50 to 200 mmscf / d (1.4 to 5.6 million cubic meters per day), preferably 75 to 200 mmscf / d (2.1 to 5.6 million cubic meters per day) (based upon the produced vapor stream from which the cooled stream is derived).

[0061]

[0057] It is envisaged that the mixing of the imported CO2 stream with the cooled stream may occur at an injection facility located on a platform where the hydrocarbon reservoir is offshore or at an injection facility located on land where the hydrocarbon reservoir is located beneath land or is close to shore.

[0062]

[0058] Typically, the cooled stream and imported CO? stream are mixed using an in-line mixing device. For example, the mixing device has an inlet for the imported CO2 stream, an inlet for the cooled stream and an outlet for the injection stream. The mixing device may have, for example, a static mixer or propeller type mixer that allows the two streams to be homogenously mixed to form the injection stream. Typically, the injection stream is then sent to a manifold that can divert the injection stream to one or more injection wells and into the reservoir.

[0063]

[0059] Where a reservoir has thermal fracturing characteristics it may be necessary to increase the diameter of the tubing in the injection well in order that a sufficient volume of the injection fluid can be injected into the reservoir to maintain cooling of the reservoir rock. Thus, the injection stream will have a lower heat capacity than water (for example, pure liquefied CO? has a specific heat capacity that is about half that of water). Also, the injection stream typically has a well-head injection temperature of about 12° C. compared with about 4 to 7° C. for injected water. Therefore higher injection rates are required to maintain cooling of the reservoir and thereby prevent fractures from closing up.

[0064]

[0060] The produced fluid stream may be passed to the production facility using a conventional flow line or riser. The production facility may be at an onshore terminal, an offshore platform or a floating structure including a floating production, storage and off-take facility (FPSO). The production facility typically comprises a gas-liquid separation stage for separating the produced vapor stream from the produced fluid, a liquid hydrocarbon-water separation stage for separating a liquid hydrocarbon stream (e.g. crude oil) from a produced water stream, a compression stage for compressing the separated vapor stream, and a cooling stage for cooling the compressed stream.

[0065]

[0061] As discussed above, the injection stream is in a dense phase state. Thus, the temperature of the injection stream is less than the temperature at the cricondentherm, more preferably, is less than the temperature at the critical point for the composition of the injection stream.

[0066]

[0062] Where an injection well has been shut-in and the column of injection fluid in the injection weil has warmed up to the geothermal gradient, it may be necessary to re-start the injection well using the imported CO2 stream, with additional pumping, owing io the reduced gravity head in the injection well. Injection of the injection stream is re-started after the warmed column of fluid has been displaced into the reservoir using the imported CO2 stream.

[0067]

[0063] The presented innovations introduces a distinctive design for the toe flap valve, effectively addressing the flow-back fluid challenge. Referring to FIG. 1, a flap valve assemblage embodying this invention is shown in assembled relationship within an injection weil tubing 140. Patent CU-75505-CNPC USA FYG

[0064] This design unequivocally eradicates the root cause of any corrosion concerns. Additionally, it is noteworthy that the flap valve configuration at the well's bottom does not induce any alterations in CO2 pressure — meaning, there is no Joule-Thomson effect. Consequently, this design also obviates the risk of low-temperature cracking.

[0068]

[0065] During the injection phase at the wellbore’s bottom, formation water becomes saturated with CO2. The injection of dry supercritical CO2is seen as a step with reduced corrosion risk, as the expulsion of water occurs during this process. However, when the well experiences a shut-in, whether it is brief or extended, the wellhead temperature drops due to supercritical CO2vaporization. This results in a coexistence of the two phases at the wellhead, causing the precipitation of free water from its initial supercritical state. This occurrence, attributed to the lower solubility of water in CO2gas compared to supercritical CO2, gives rise to corrosion challenges at the well's upper section. In the case of extended shut-ins, there is no doubt that direct contact with flow-back fluid exacerbates the corrosion issues at the bottom. Different from traditional oil and gas production wells, in the CCS or CCUS injection wells, shut-in is frequently mainly due to intermittent operation process

[0069]

[0066] Beyond the requirement for materials to withstand these harsh corrosion-inducing conditions, they must also possess sufficient toughness to withstand low temperatures resulting from the Joule-Thomson effect. An extreme hypothetical involves an uncontrolled and unexpected well depressurization down to atmospheric pressure, leading to a CO2temperature drop to -78.5°C. In such a scenario, modeling indicates metallic temperatures would closely approach the CO2triple point (-56.6°C). This severe cold would necessitate the selection of specialized and more expensive corrosion-resistant alloys (CRA) capable of enduring such low temperatures. From this detailed process, it becomes evident that all corrosion issues stem from the formulation fluids' flow-back after the well's shut-in. The presence of these formulation fluids in the flow-back significantly contributes to the corrosion problems. The core corrosion challenges would cease to exist if measures were taken to prevent the flow-back of these formulation fluids into the tubing.

[0070]

[0067] As shown in FIG. 1, an apparatus 100 for internal corrosion prevention in carbon capture utilization and storage injection well tubing 140 may comprise a flap valve 120 at a bottom end 146 of the injection well tubing 140 that operates by responding to elevated injection pressures and automatically closes upon injection cessation, effectively preventing a flow-back of formulation fluids into the injection well tubing 140.

[0071]

[0068] In one embodiment, the flap valve 120 may contact with the tubing to create a tight seal when the injection pressure is below a certain threshold, such as atmospheric pressure, for example. The flap valve is configured to achieve gas tight seal, and keep the sealing performance with large temperature cycle from -80°C to 150°C in short period of time (1-20 mins), for example.

[0072]

[0069] In one embodiment, the flap valve is made from at least one of specific alloys comprising Ni alloy (625, C-276), Ti alloy, Super Austenitic Stainless, for example, to address environmental cracking at extremely low temperatures.

[0073]

[0070] The International Organization for Standardization (ISO) and the American Petroleum Institute(API) have created a standard [reference ISO 14310:2001 (E) and API Specification intended to establish guidelines for both manufacturers and end users in the selection, manufacture, design, and laboratory testing of the many types of packers available on today’s market. Perhaps more importantly, the standards also establish a minimum set of parameters with which the manufacturer must comply to claim conformity. The International Patent CU-76505-CNPC USA FYG Standard is structured with the requirements for both quality control and design verification in tiered rankings. There are three grades, or levels, established for quality control and six grades (plus one special grade) for design verification.

[0074]

[0071] The quality standards range from grade Q3 to Q1, with grade Q3 carrying the minimum requirements and Q1 outlining the highest level of inspection and manufacturing verification procedures. Provisions are also established to allow the end user to modify the quality plans to meet his specific application by including additional needs as “supplement requirements."

[0075]

[0072] The six standard design-validation grades range from V6 to V1. V6 is the lowest grade, and V1 represents the highest level of testing. A special VO grade was included to meet special acceptance criteria requirements. The following is a brief summary outlining the basic requirements of the various levels of test-acceptance criteria.

[0076]

[0073] V6 is the lowest grade established. The performance level in this instance is defined by the manufacturer for products that do not meet the testing criteria found in grades V0 through V5.

[0077]

[0074] In this V5 grade, the packer must be set in the maximum inner diameter (ID) casing it is rated for at the maximum recommended operating temperature. The testing parameters require that it be set with the minimum packoff force or pressure as specified by the manufacturer. The pressure test is performed with water or hydraulic oil to the maximum differential-pressure rating of the packer. Two pressure reversals across the tool are required, meaning it must be proved that the packer will hold pressure from both above and below. The hold periods for each test are required to be a minimum of 15 minutes long. At the end of the test, retrievable packers must be able to be removed from the test fixture by using the procedures of its intended design.

[0078]

[0075] In this V4 grade, all parameters covered in Grade V5 apply. In addition to passing V5 criteria, it also must be proved that the packer will hold differential pressure in combination with compression and tensile loads, as advertised in the manufacturer’s performance envelope.

[0079]

[0076] All test criteria mandated in Grade V4 apply to V3. To achieve V3 certification, the packer also must pass a temperature cycle test. In the temperature cycle test, the packer must hold the maximum specified pressure at the upper and lower temperature limits in which the packer is designed to work. The test is started at maximum temperature, as in V4 and V5. After passing this segment of the test, the temperature is allowed to cool to the minimum, and another pressure test is applied. After successfully passing the low-temperature test, the packer also must pass a differential-pressure hold after the test-cell temperature is raised back to the maximum temperature.

[0080]

[0077] The same test parameters used in V4 apply to Grade V2, but the test medium is replaced with air or nitrogen. A leak rate of 20 cm3 of gas over the hold period is acceptable, however, the rate may not increase during the hold period.

[0081]

[0078] The same test parameters used in V3 apply to Grade V1, but the test medium is replaced with air or nitrogen. Similar to the V2 test, a leak rate of 20 cm3 of gas over the hold period is acceptable, and the rate may not increase during the hold period.

[0082]

[0079] Special Grade VO Gas Test + Axial Loads +Temperature Cycling + Bubble Tight Gas Seal This is a special validation grade that is added to meet customer specifications in which a tight-gas seal is required. The test parameters are the same as those for V1, but a gas-leak rate is not allowed during the hold period. Patent CU-76505-CNPC USA FYG

[0080] If a packer is qualified for use in a higher grade, it may be deemed suitable for use in any of the lower validation grades. For example, if tested to grade V4, it is accepted that the packer meets or exceeds the service requirements of V4, V5, and V6 applications.

[0083]

[0081] In one embodiment, the flap valve 120 may be rotatable between open and closed position for controlling the flow in the injection well tubing. The flap valve 120 may further comprise a flapper hinge 130 about which the flap valve 120 rotates.

[0084]

[0082] In one embodiment, the flap valve 120 may further comprise a valve seat 150 to hold pressure exerted on an outer surface 160 in the closed position. The valve seat 150 defines at its bottom end an annular, cylindrically shaped sealing surface. The area that the valve seat 150 covers is substantially the same as the area of the inner diameter injection well tubing. The circumference of the valve seat 150 may be substantially same as that of the inside injection well tubing. An elastomeric seal may be inserted in such surface.

[0085]

[0083] In one embodiment, the flapper hinge 130 may comprise a hinge pin 170 formed on said flap valve 120. In one embodiment, the flap valve 120 may further comprise a torsion spring means 180 being loaded in torsion as the flap valve 120 rotates from the closed to the open position to exert a restoring force for rotating the valve flapper 120 to the closed position.

[0086]

[0084] When the flap valve 120 is pivoted about hinge pin 170 to its substantially vertical, open position as shown in FIG. 1, it provides unrestricted fluid passage through such bore. The flap valve 120 may be shifted from its horizontal closed position to its substantially vertical open position by the downward movement of fluid, such as liquid carbon dioxide.

[0087]

[0085] It will be apparent to those skilled in the art that the torsion spring means 180 is in torsion relative to the flap valve 120 so that the pivotal movement of the flap valve 120 from its horizontal closed position to its vertical open position shown in FIG. 1 is opposed by a spring bias produced by the torsionally winding of the torsion spring means 180. Thus, the flap valve 120 is normally biased to its closed position and may return to such position whenever there is a shut-in either a short term shut-in or long term shut-in.

[0088]

[0086] The flap valve 120 may have a ridge 190 on a central outer surface 160 of the flap valve 120 to make it much more sturdy and withhold the pressure builds up during the shut-in.

[0089]

[0087] In one embodiment, the torsion spring means 180 has one end 182 that connects and biases on the outer surface 160 of the flap valve 120, while the other end 184 connects and biases on the outer surface of the injection well tubing 140.

[0090]

[0088] In another embodiment, as shown in FIG. 2, the torsion spring means may be a double torsion spring, which has springs 210 and 220 with both ends 212, 222 respectively connecting and biasing on the outer surface of the injection well tubing 140. The torsion spring means 210 and 220 have another merged end 226 connecting and biasing on the outer surface of the flap valve 120.

[0091]

[0089] Still in FIG. 2, the flap valve 120 has a curved configuration as compared to substantially flat configuration at the bottom of flap valve 120 shown in FIG. 1. It will be understood that by those skilled in the art that both a curved flow tube and a curved flapper are not essentially related to the position of the spring utilized herein. The spring can be employed with a more conventional injection well tubing and flapper valve configuration. Furthermore, the curved flap valve configuration, and annular torsion spring, can be employed with an injection well tubing having a flat end and still achieve a significant increase in flow area. Patent CU-76505-CNPC USA FYG

[0090] Throughout the injection process, the valve operates by responding to elevated injection pressures. Positioned at the tubing's bottom end, the valve's operation neither constrains the injection flow rate nor induces the Joule-Thomson effect. Upon injection cessation, this flap valve automatically closes, effectively preventing the flow-back of formulation fluids. This action decisively eliminates all the factors contributing to corrosion issues. Functioning as a check valve, this flap valve can be designed and manufactured to achieve gas-tight sealing.

[0092]

[0091] While this valve, along with the outer diameter of the tubing beneath the packer, remains exposed to downhole fluids, they are crafted from corrosion-resistant alloys (CRA) like 25Cr or Super 13Cr. On the other hand, the tubing section above the packer can be constructed from cost-effective low-alloy steel, such as L80. As a result, significant cost savings can be realized.

[0093]

[0092] The foregoing disclosure and description of the invention is illustrative and explanatory thereof. Various changes in the details of the illustrated structures, construction and method can be made without departing from the true spirit of the invention.

Claims

Patent CU-75505-CNPC USA FYG CLAIMSWe claim:

1. A method of preventing internal corrosion in carbon capture utilization and storage injection well tubing and storing CO2 in a hydrocarbon reservoir having at least one injection well, comprising:importing a CO2 stream to an injection facility wherein the imported CO2 is either in a liquid state or a supercritical state;injecting the CO2 stream into the hydrocarbon bearing reservoir from said injection well;using a flap valve at a bottom end of an injection well tubing that operates by responding to elevated injection pressures and automatically closes upon injection cessation, effectively preventing a flow-back of fluids into the injection well tubing;continuing injecting the CO2 stream into the hydrocarbon bearing reservoir; andpushing the flap valve open through the pressure of the liquid CO2 stream into the hydrocarbon bearing reservoir.

2. The method of claim 1, wherein the flap valve is configured to achieve gas tight seal, and keep the sealing performance with large temperature cycle from -80°C to 150°C in short period of time (1-20 mins) during the carbon capture utilization and storage (CCUS) operation.

3. The method of claim 1 or 2, wherein the flap valve is made from at least one of specific alloys comprising Ni alloy (625, C-276), Ti alloy, Super Austenitic Stainless, to address environmental cracking at extremely low temperatures.

4. The method of any one of claims 1-3 further comprising a valve seat to hold pressure exerted on an outer surface of the flap valve in the closed position.

5. The method of any one of claims 1-4, wherein said flapper hinge comprises a hinge pin formed on said flap valve.Patent CU-76505-CNPC USA FYG 6. The method of any one of claims 1 -5, further comprising a torsion spring means being loaded in torsion as the flap valve rotates from the closed to the open position to exert a restoring force for rotating the valve flapper to the closed position.

7. The method of any one of claims 1-6, wherein the torsion spring means has one end connecting and biasing on the outer surface of the flap valve, while the other end connects and biases on the outer surface of the injection well tubing.

8. The method of any one of claims 1-7, wherein the torsion spring means has both ends connecting and biasing on the outer surface of the injection well tubing.

9. A method for controlling flow in an injection well tubing and preventing internal corrosion of the injection well tubing, comprising:injecting CO2 stream into a hydrocarbon bearing reservoir from an injection well; andusing a flap valve at a bottom end of an injection well tubing that operates by responding to elevated injection pressures; andautomatically closing upon injection cessation, effectively preventing a flow-back of fluids into the injection well tubing, wherein the flap valve is configured to achieve gas tight seal, and keep the sealing performance with large temperature cycle from -80°C to 150°C in short period of time (1-20 mins).

10. The method of claim 9, further comprises steps ofcontinuing injecting the GO2 stream into the hydrocarbon bearing reservoir; andpushing the flap valve open through the pressure of the liquid CO2 stream into the hydrocarbon bearing reservoir.

11. The method of claim 9 or 10, wherein the flap valve having a torsion spring means with one end connecting and biasing on an outer surface of the flap valve, while the other end connects and biases on the outer surface of the injection well tubing.Patent CU-76505-CNPC USA FYG 12. The method of any one of claims 9-11, wherein the flap valve comprises a valve seat to hold pressure exerted on an outer surface of the flap valve in the closed position, wherein area that the valve seat covers is substantially the same as the area of the inner diameter of injection well tubing.

13. The method of any one of claims 9-12, wherein said flapper hinge comprises a hinge pin formed on said flap valve.

14. The method of any one of claims 9-13, wherein the torsion spring means is secured to the hinge pin.

15. The method of any one of claims 9-14, wherein the torsion spring means is loaded in torsion as the flap valve rotates from the closed position to the open position to exert a restoring force for rotating the valve flapper to the closed position.

16. The method of any one of claims 11, wherein said spring means comprises a coil spring, rotation of said flap valve about an axis of rotation to open said flap valve loading said springs in torsion.

17. A method of preventing internal corrosion in carbon capture utilization and storage injection well tubing and storing CO2 in a hydrocarbon reservoir having at least one injection well, comprising:injecting the CO2 stream into the hydrocarbon bearing reservoir from said injection well;using a flap valve in contact with the tubing to create a tight seal when the injection pressure is below a certain threshold, wherein the flap valve is configured to achieve gas tight seal, and keep the sealing performance with large temperature cycle from -80°C to 150°C in short period of time (1-20 mins), wherein the flap valve comprises:torsion spring means comprising a coil spring, rotation of said flap valve about an axis of rotation to open said flap loading said spring means in torsion, a valve flapper rotatable between open and closed positions for controlling the flow in the fluid transmission conduit, wherein the flap valve's operation neither constrains the injection flow rate nor induces the Joule-Thomson effect.Patent CU-75505-CNPC USA FYG 18. The method of claim 17, wherein said torsion spring means comprise coil springs, rotation of said valve flapper about said axis of rotation to open said flap loading said springs in torsion.

19. The method of claim 17 or 18, wherein the torsion spring means has one end that connects and biases on an outer surface of the flap valve, while the other end connects and biases on the outer surface of the injection well tubing.

20. The method of any one of claims 17-19, wherein the torsion spring means has both ends connects and biases on the outer surface of the injection well tubing.

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