Toe Flap Valve for Internal Corrosion Prevention in Ccus Injection Well Tubing

This application is a continuation-in-part of U.S. patent application Ser. No. 18/639,181, filed on Apr. 18, 2024, hereby incorporated by reference in its entireties.

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 COin a hydrocarbon reservoir.

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.

In actuality, the injected COstream 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 COstream undergoes through dehydration prior to transportation through carbon steel COpipelines. In simpler terms, the challenge within the injection well stems not from the COstream itself, but rather from the interaction between this stream and the water phase present within the reservoir.

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

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

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 elevated injection pressures and automatically closes upon injection cessation, effectively preventing a flow-back of formulation fluids into the injection well tubing.

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

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

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.

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

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.

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.

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

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.

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.

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

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.

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

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

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.

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.

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 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.

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.

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.

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

In further embodiment, a method of preventing internal corrosion in carbon capture utilization and storage injection well tubing and storing COin a hydrocarbon reservoir having at least one injection well. The method may comprise steps of importing a COstream to an injection facility wherein the imported COis either in a liquid state or a supercritical state; injecting the COstream 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 COstream into the hydrocarbon bearing reservoir; and pushing the flap valve open through the pressure of the liquid COstream into the hydrocarbon bearing reservoir.

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 COstream 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.

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.

In still further embodiment, a method of preventing internal corrosion in carbon capture utilization and storage injection well tubing and storing COin a hydrocarbon reservoir having at least one injection well may comprise steps of injecting the COstream 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).

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.

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”.

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.

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%.

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 COis a state that has a large number of moles of COper unit volume. Also, as there are no interface characteristics, it is implicit that a dense phase fluid will be single phase.

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).

The “cricondentherm” for a multi-component composition is the highest temperature at which two phases can co-exist.

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.

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

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.

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 COin 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 COstream. Typically, the oil field should have an injection facility and injection pipelines for a plurality of injection wells.

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 COfrom the production well ceases, injection of the injection stream will also cease and the emplaced volume of COwill be sequestered. Production of hydrocarbons and water from the oil reservoir, during injection of the injection stream, is essential to create space for the COthat 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 COthat can be sequestered is consequently reduced.

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

Although the imported COstream is not a single component stream, the amount of impurities in the imported COstream is so low that the phase behavior of this stream is similar to that of pure CO. Accordingly, the imported COmay be regarded as being either in a liquid or a supercritical state. By “supercritical state” is meant that the imported COhas a pressure above the critical pressure for pure COand a temperature above the critical temperature for pure CO. Thus, compressing pure COat 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 COat or above its critical temperature and critical pressure increases its density to a liquid-like state but does not effect a phase change. At or above the critical point, COis termed a supercritical fluid. Although supercritical COcan 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.

The imported COstream 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 COstream to the injection facility. Where the imported COstream arrives by pipeline, the COis 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 COthat 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 COstream will be above the cricondenbar for all compositions of the injection stream (irrespective of the molecular fraction of COin the injection stream). It is envisaged that the imported COstream may arrive by pipeline at the desired well-head pressure for the injection stream. Alternatively, the pipeline pressure of the imported COstream may be below the desired well-head pressure for the injection stream. Accordingly, the pressure of the imported COstream 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 COstream with the cooled stream at the arrival pressure of the imported COstream and then subsequently boost the pressure of the injection stream to the desired well-head pressure. Typically, the imported COwill 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 COinjection 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.

It is also envisaged that the imported COmay be delivered to the injection facility by tanker (road, rail or ship). Where the COis transported to the injection facility by tanker, the COwill generally be in a liquid state. The tanker typically comprises a pressurized container for the liquid CO, a cargo discharge pump within said container for pumping the COout of the container along a conduit to the injection facility (thereby providing the imported COstream). Typically, an external booster pump is also provided for pumping the imported COstream to the injection facility. The COthat is transported by tanker is generally refrigerated otherwise the pressures required to maintain the COin 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 COwill be in the range of −55 to −48° C., preferably −57 to −40° C.; 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 COwhich is just above the triple point in terms of temperature and pressure. The triple point for pure COis 5.2 bar (0.52 MPa) absolute and −56.6 C. Typically, the imported COstream 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 COstream 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 COstream 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 COin a liquid state via tanker at sub-ambient temperatures is expensive since refrigeration is required. Also, there is a risk that refrigeration of the COmay result in the formation of solid CO. Accordingly, transportation by pipeline is preferred.

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.

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.

As noted 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 COto 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 COis 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”).

On land-based hydrocarbon reservoirs an arrangement of production and injection wells is commonly employed in oil production, for example a geometric arrangement 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 COinjected 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 CO: storage by maximizing the reservoir volume between an injection well and production well.