Patent Application
20230313632
For oil and gas drilling and production from subterranean reservoirs, after a well is drilled, cleaned, and structured with a casing and cement, a production tubing is run into the well for producing wellbore fluids such as oil and gas from the well to the surface. Wellbore fluids produced from the reservoir or formation often do not have sufficient formation pressure to drive the wellbore fluids to the surface.
For example, as the production operation progresses, the reservoir pressure depletes. This results in a decline in the ability of the produced fluid velocity to lift the fluid to the surface. Therefore, the overall wellbore fluid production rate declines with time. Especially for production tubes with a large inner diameter, the ability of gas velocity to lift wellbore fluids from the downhole to the surface reduces to a great extent. For an efficient process of wellbore fluid production, it is important to maintain a critical rate of fluid pressure in the production tubing in order to lift wellbore fluids to the surface. Therefore, the produced fluid pressure is artificially increased utilizing a variety of techniques.
One such technique includes removing production tubing from a well and installing new production tubing having a smaller inner diameter in the well. The smaller inner diameter may provide increased pressure within the production tubing, which may help in moving the produced fluids to the surface. Another technique includes installing downhole pumps (e.g., an electric submersible pump (ESP)) downhole, which may pump and lift fluids through the production tubing to the surface.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
In one aspect, embodiments disclosed herein relate to a tubing that includes an outer pipe, an inner pipe, and an intermediate layer positioned between the outer pipe and the inner pipe, wherein the intermediate layer comprises an elastomer that is swellable in a fluid.
In another aspect, embodiments disclosed herein relate to a method for using a contractible tubing having an outer pipe, an inner pipe, and an intermediate layer disposed between the outer pipe and the inner pipe, wherein the intermediate layer includes an elastomer. The method includes opening a fluid passage to the intermediate layer to contact the intermediate layer with a fluid and swell the elastomer. The swelling of the elastomer is used to apply a force on the inner pipe and contract the inner pipe, such that the inner pipe has a first inner diameter prior to contacting the intermediate layer with the fluid, and a second inner diameter smaller than the first inner diameter after contacting the intermediate layer with the fluid.
In yet another aspect, embodiments disclosed herein relate to a system that includes a contractible tubing positioned in a well. The contractible tubing may be used as production tubing and may include an intermediate layer provided between an inner pipe and an outer pipe, wherein the intermediate layer includes an elastomer that is swellable in a fluid. At least one fluid passage may fluidly connect an environment around the contractible production tubing to the intermediate layer, and a closure element may block fluid flow through the fluid passage.
Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.
Wherever possible, like or identical reference numerals are used in the figures to identify common or the same elements. The figures are not necessarily to scale and certain features and certain views of the figures may be shown exaggerated in scale for purposes of clarification.
Certain embodiments of the present disclosure will be described in detail with reference to the accompanying figures. It should be understood, however, that the accompanying figures illustrate the various implementations described and are not meant to limit the scope of various technologies described. Further, in the following detailed description of embodiments of the present disclosure, numerous specific details are set forth in the following detailed description in order to provide a more thorough understanding of embodiments of the present disclosure. However, it will be apparent to one of ordinary skill in the art that the present disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.
Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create a particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as by the use of the terms “before,” “after,” “single,” and other such terminology. Rather the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.
Embodiments disclosed herein relate generally to tubing that may be used for the transport of fluids (e.g., in the oil and gas industry for the transport of hydrocarbon fluids). As used herein, fluids may refer to slurries, liquids, gases, and/or mixtures thereof. In the oil and gas industry, the term “produced fluid” may encompass liquids and gases and refers to the extracted fluid from a reservoir. Such extracted fluids may include, for example, a wide variety of hydrocarbons, including hydrocarbon liquids or hydrocarbon gases, water, or mixtures thereof. Tubing may include rigid segments of pipes axially connected together in an end-to-end fashion at tool joints or may be a continuous line of flexible pipe (e.g., coiled tubing). Tubing may be made of metal or composite materials.
Tubing used for the production of hydrocarbon from a downhole location to a surface facility of a production system may be referred to as production tubing. Production tubing may provide a continuous flow path from the production zone of a well to the wellhead through which oil, gas, or other fluids may be produced. Production tubing may protect wellbore casing from wear, tear, corrosion, and deposition of by-products including sand, silt, paraffin, and asphaltenes. Multiple production tubing strings may be set up in a single wellbore if there is more than one zone of production in the well.
Conventional production tubing may need to be changed out over the life of a production operation from a well to provide differently sized tubing (and thus different fluid pressure therethrough) in response to decreasing amounts of fluids being produced from the well. However, according to embodiments of the present disclosure, a tubing may be designed to have a contractible inner diameter, which may be contracted without removing or uninstalling the tubing. Tubing having a contractible inner diameter according to embodiments of the present disclosure may be referred to herein as contractible tubing. As described in more detail below, contractible tubing may have flexibility in its size and shape, may be deformed, and may be reduced in dimension upon applying a force or an external factor.
Contractible tubing according to embodiments of the present disclosure that is capable of being contracted, or capable of having its inner diameter decreased in size under stress, may be used in the oil and gas industry or in other fluid transport applications. It is to be further understood that the various embodiments described herein may be used in various stages of a well, a non-limiting example of which is producing fluids from a well (e.g., as production tubing). The different embodiments described herein may provide a contractible production tubing that may play a valuable and useful role in the life of a well. Further, an overall system including contractible production tubing configuration and arrangement of components for producing fluid from a well according to one or more embodiments described herein may provide a cost-effective alternative to conventional systems. The embodiments are described merely as examples of useful applications, which are not limited to any specific details of the embodiments herein.
For example, contractible production tubing according to embodiments of the present disclosure may be used for the production of hydrocarbon fluids from a well. Hydrocarbon fluids may be located below the surface of the Earth in subterranean porous rock hydrocarbon-bearing formations called reservoirs. In order to extract the hydrocarbons, wells may be drilled and cleaned out to gain access to the hydrocarbon-bearing formations using traditional drilling and pumping methods, a non-limiting example of such may be fracturing. Once the well is established, fluids may be extracted from the formations and directed to the surface of the well via contractible production tubing according to embodiments of the present disclosure.
In some embodiments, contractible production tubing may be used to maintain a downhole critical rate of a gas well to lift liquid to the surface by reducing the inner diameter of the contractible production tubing. As used herein, the term “critical rate” means the minimum rate of gas to ensure the lifting of heavier liquid-like condensate and water to the surface. As production continues, the reservoir pressure declines, therefore, the rate of gas to lift liquid to the surface also declines. The critical rate is not a function of liquid production; instead, it is based on what rate or velocity may lift the liquid from the well up to the surface and at what minimum value it may no longer lift the liquid up, therefore, resulting in possible liquid loading. As used herein, the term “liquid loading” means the inability of a producing gas well to remove its coproduced liquids from the wellbore. Liquid flowing as droplets or film accumulates at the well bottom, thereby imposing backpressure at the surface and triggering increasingly higher-pressure loss in the wellbore. Liquid loading in gas wells may be prevented by using a contractible production tubing according to embodiments of the present disclosure to produce fluids from the well by reducing the inner diameter of the contractible production tubing as reservoir pressure decreases.
As production fluids are extracted through a wellbore, the reservoir pressure changes, and therefore, the flow properties of a fluid in a wellbore change. As the reservoir pressure depletes, the rate of gas flow declines, and therefore, the ability of the gas velocity to lift liquid to the surface reduces. For bigger tubing sizes (with a relatively larger inner diameter), this is a bigger challenge. By using contractible production tubing according to embodiments of the present disclosure to produce liquids from a gas well, the inner diameter of a contractible production tubing may be reduced without removing and exchanging the production tubing in order to increase pressure within the production tubing and lift liquid to the surface in an efficient manner.
The contractible production tubing 122 may include three concentrically positioned layers formed by an inner pipe 104, an intermediate layer 106, and an outer pipe 108. According to embodiments of the present disclosure, contractible production tubing may extend a depth into a well 112 for production operations by connecting a series of contractible tubing segments together (e.g., at tool joints) to form a string of contractible tubing. Each contractible tubing segment may include a layered assembly of an inner pipe 104, an outer pipe 108, and an intermediate layer 106 disposed between the inner pipe 104 and outer pipe 108. When the contractible tubing segments are connected together in an end-to-end fashion, the inner pipe 104 of the string of contractible tubing defines the inner diameter along the length of the contractible production tubing 122.
The inner pipe 104 may be deformable (such that it may be contracted), and the outer pipe 108 may be rigid. The intermediate layer 106 may be made of an elastomer material that is swellable when exposed to a fluid. Additionally, at least one fluid passage may be provided along the contractible production tubing 122 that fluidly communicates an outer surface of the contractible production tubing 122 with the intermediate layer 106. For example, fluid passage(s) may extend through the length of the contractible production tubing 122, may extend through the inner pipe 104 (communicating the inner volume of the tubing with the intermediate layer), or may extend through the outer pipe 108 (communicating the exterior environment of the tubing with the intermediate layer).
Additionally, the fluid passage(s) may be blocked (e.g., using a valve, a sliding sleeve, a seal, or other blocking components) until activated to an open position. For example, in some embodiments, a blocking component 110 may be held in a closed position by a shear pin to block fluid flow through a fluid passage. When the shear pin is broken, the blocking component is free to move to an open position and allow fluid flow through the fluid passage. In some embodiments, a shear pin may act as a blocking component that seals a fluid passage, where breaking the shear pin opens the fluid passage. Various examples of mechanisms and components are described below for blocking and opening a fluid passage through a contractible tubing according to embodiments of the present disclosure. However, upon reading this application, a person skilled in the art may appreciate variations of such examples may be used to block and open a fluid passage.
In one or more embodiments, a hydraulic control system 120 provided at the surface 116 may be used to activate the opening of a fluid passage. For example, the hydraulic control system 120 may send an electric signal downhole to activate a hydraulic system that hydraulically opens the blocking component, thereby allowing fluid to contact and swell the intermediate layer 106. In such manner, the swelling of an intermediate layer 106 may be hydraulically controlled from the surface 116 of the well 112.
When the fluid passage(s) is open, fluid may contact the intermediate layer 106, which swells the elastomer. The intermediate layer may be permeable, which may allow fluid to flow through the elastomer and uniformly expand the elastomer throughout the layer. Because fluid permeability through the elastomer layer may take time (e.g., 1 day, 2 days, or more) to evenly distribute through the layer and provide uniform expansion of the intermediate layer, multiple fluid passages may be provided to provide multiple fluid access points along the intermediate layer 106 and expedite fluid-elastomer interaction and intermediate layer expansion. The intermediate layer 106 may swell to a maximum value to reduce the inner diameter of the contractible production tubing along part of or the entire length of the contractible tubing.
“Expansion ratio” of the elastomer may be defined as the volume of swelled elastomer layer divided by the volume of the elastomer layer before any swelling. This expansion ratio may be pre-designed to cover the design volume of space needed for the reduction of the inner diameter of the contractible tubing.
The inner pipe 104 may be made of a material capable of contracting when the force from the intermediate layer 106 that is under swelling pushes on the inner pipe 104, thereby reducing the inner diameter of the contractible production tubing 122. For example, an inner pipe may be made of a deformable alloy, such as malleable iron or mild steel. In some embodiments, deformability of the inner pipe may be increased by decreasing its wall thickness. The inner pipe 104 may have a clearance to permit movement of the intermediate layer 106 upon swelling. Swelling of the intermediate layer 106 may force the inner pipe 104 radially inward (toward a central longitudinal axis of the inner pipe), thereby achieving a smaller tubing inner diameter of the contractible production tubing 122.
The intermediate layer 106 may swell uniformly in both axial and radial directions. However, tool joints or other axial connections along the contractible production tubing 122 may act as axial caps to limit axial expansion of the elastomer along the length of the contractible production tubing 122 and allow maximum radial expansion of the elastomer, thereby maximizing contraction of the tubing inner diameter. Contracting or reducing the inner diameter of the contractible production tubing 122 may increase the pressure of fluid flowing through the contractible production tubing 122. Such increased fluid pressure within the contractible production tubing 122 may aid in flowing fluids from the reservoir 118 to the surface of the well 112.
A contractible production tubing according to embodiments of the present disclosure may be used in various well systems, where the contractible tubing may include an inner pipe, an intermediate layer, and an outer pipe. The intermediate layer may be positioned such that it stays in between the outer pipe and the inner pipe. When in contact with a fluid, the intermediate layer may be swellable, while the outer pipe may be rigid, and the inner pipe may be contractible. The contractible production tubing may also include a fluid passage fluidly connecting an environment around the tubing to the intermediate layer, a closure element blocking fluid flow through the fluid passage, and an activation element that opens the fluid passage. The fluid passage may be opened to contact the intermediate layer with a fluid and swell the elastomer layer, which may constrict the inner pipe to reduce the inner diameter of the contractible production tubing.
The contractible production tubing 200 includes an inner pipe 202, an intermediate layer 206, and an outer pipe 204. The inner diameter 208 of the contractible production tubing 200 is measured as the inner diameter of the inner pipe 202. The contractible production tubing 200 may also include a fluid passage 207 fluidly connecting an environment around the tubing (e.g., an exterior around the outer surface of the tubing or an interior within the inner surface of the tubing) to the intermediate layer 206. A closure element may block fluid flow through the fluid passage 207, and an activation mechanism may open the fluid passage 207.
Various types of systems and mechanisms may be used to block and open the fluid passage 207. For example, in the embodiment shown in
In one or more embodiments, a shear pin may be a shearable piece of material designed to break, or shear, when a force is applied, such as from an external pressure source. The minimum amount of pressure needed to break a shear pin may be referred to as the “shear off pressure.” Shear off pressure may be calculated based on the completion design, type of well, and production profile anticipated for the well. The shear off pressure may be applied to break a shear pin such that a fluid passage 207 between the intermediate layer 206 and a surrounding fluid environment is opened. In one or more embodiments, the shear pin may comprise a metal alloy such as brass and steel. Shear pins made of brass may require less shear off pressure than shear pins made of steel.
In one or more embodiments, depending on the design requirement, a plurality of shear pins may be utilized. In one or more embodiments, multiple shear pins may be utilized on a single contractible tubing segment. For example, three to four shear pins may be utilized per contractible tubing segment, where each shear pin 209 may block a fluid passage 207. The shear pin 209 may be designed to have the same shear off pressure, such that the shear pin 209 may be broken at substantially the same time upon application of a pressure above the shear off pressure to allow fluid flow. In such manner, a plurality of shear pins on the body of a contractible production tubing may be broken at or around the same time, and fluid channels may be opened at or around the same time, by applying a pre-determined shear off pressure within the tubing. A non-limiting example method for breaking a plurality of shear pins may be by adjusting the well pressure at the wellhead.
The shear pins may shear off when a pressure above the shear off pressure is applied. For example, a fluid within the inner diameter of the contractible tubing may be pressurized at a pressure above the shear off pressure of shear pins positioned along the inner diameter of the contractible tubing. By applying a pressure above the shear off pressure, the shear pins may be broken to open fluid passages formed through the contractible tubing and allow fluid to enter into the fluid passages and contact the elastomer layer. When in contact with fluid, the elastomer layer may swell and push on the inner pipe of the contractible tubing to decrease the diameter of the inner pipe, and thereby increase the fluid pressure within the contractible tubing. In one or more embodiments, the swelling of the elastomer layer may be irreversible, and the elastomer layer may not return back to its original shape or size before swelling. The shear off pressure needed to break a shear pin may depend on the material of construction, the configuration, and the size of the shear pin. In one or more embodiments, the shear off pressure needed to break a shear pin may be designed based on maximum production pressure in a well. The shear pin pressure may be set above the maximum production pressure in order to prevent premature shearing of the pin. For a non-limiting example, in one or more embodiments, the shear off pressure of a shear pin may be designed to be 500 psi over the maximum production pressure in a well.
In some embodiments, more than one closure element may be assembled and used to block a fluid passage through a contractible production tubing. For example, a closure element assembly may include a shear pin and a sleeve (or other sliding components), where the shear pin may be installed along the contractible production tubing to retain the sleeve in a fixed position covering the fluid passage until sufficient force is applied to break the shear pin. When a pressure above the shear off pressure is applied, the shear pin may break and allow the sleeve to move and uncover the fluid passage, thereby allowing the fluid to enter into the tubing through the uncovered fluid passage.
For example,
A shear pin may be broken in order to open a fluid passage along a contractible production tubing using different mechanisms. For a non-limiting example, sleeves may be shifted to open by utilizing an electrical signal which may be sent via a slickline unit. To operate using electrical signals, a source of electricity may be required at the surface. Once the shear pin is sheared or broken by applying a force, the sleeve may then move to open a fluid passage with the intermediate layer. In one or more embodiments, a shear pin may be initially attached to the inner pipe of the contractible production tubing such that it is in communication with a hydraulic control system, which may apply hydraulic pressure to break the shear pin.
In one or more embodiments, breaking one or more shear pins may allow a fluid to flow through one or more fluid channels to contact and swell an elastomer layer uniformly around the entire circumference of the contractible tubing and along at least a partial length of the contractible tubing. Thus, after opening fluid channels to contact and swell an elastomer layer with a fluid, the elastomer layer may uniformly increase in thickness in both axial and circumferential directions.
As used herein, the term “swelling” means an increase in the volume of an elastomer with the uptake of a liquid or gas. An elastomer is a polymer with viscoelasticity and with weak intermolecular forces, generally low Young's modulus and high failure strain compared with other materials. Elastomers include rubbery materials composed of long chainlike molecules, or polymers, having elastic properties. Elastomers may be made of a matrix of natural or synthetic polymer material. The elasticity is derived from the ability of the long-chain molecules to reconfigure themselves to distribute applied stress when a force is applied. Elastomers may recover to their original shape after being temporarily deformed with stress due to their stretchable covalent cross-linking bonds. Depending on the chemical structure, elastomers may be stretched from 5 to 700% of their original shape under a given stress. The elasticity may also be affected by the temperature. When the cross-linking covalent bonds break, the elastomers may be permanently deformed. When liquid or gas molecules penetrate an elastomer layer, they interact with the polymers of elastomers and stay local through forming hydrogen bonds which increases pressure on the elastomer chains and results in swelling of the elastomers. The term “fully swelled” here means the elastomer layer being swelled in a fluid in such a way that it is at its highest capacity for holding fluid in its matrix. When fully swelled, an elastomer layer may not return to its original size and shape.
Referring again to
As the intermediate layer 206 swells, the thickness of the intermediate layer 206 (as measured along a radial distance between an inner surface and outer surface of the elastomer layer) may increase. The swelling of the intermediate layer 206 may exert a force on the surrounding components including the inner pipe 202 and outer pipe 204 of the contractible production tubing 200. According to embodiments of the present disclosure, an inner pipe 202 may be made to have a relatively greater deformability compared with an outer pipe 204, such that force from the intermediate layer 206 that is swelling constricts the inner pipe 202 before deforming the outer pipe 204. For example, the inner pipe 202 may be made of a deformable, and thus contractible, material, and the outer pipe 204 may be made of a rigid material (having less malleability than the inner pipe material), such that the force from the elastomer swelling may constrict the inner pipe 202 (push the inner pipe 202 radially inward) while the outer pipe 204 maintains its shape and size. A non-limiting example of such rigid material for the construction of outer pipe may be iron or carbon steel. In some embodiments, the inner pipe 202 may be made to have greater deformability than the outer pipe 204 by reducing the wall thickness of the inner pipe 202 compared to the wall thickness of the outer pipe 204.
After swelling the intermediate layer 206, the inner diameter 208 of the contractible production tubing 200 defined by the inner pipe 202 may be reduced from an initial value of the inner diameter 208, as shown in
In one or more embodiments, the intermediate layer may comprise a liquid-swellable elastomer (e.g., an elastomer swellable in water) or a gas-swellable elastomer. The intermediate layer may be constructed with a super absorbent polymer (SAP) blended into a base elastomer compound. When the elastomer layer is exposed to a liquid, the SAP may absorb the liquid causing the overall volume of the elastomer layer to increase. Non-limiting examples of such SAP may be sodium polyacrylate or polyacrylamide copolymer, and the base elastomer may be any other compatible elastomer.
In one or more embodiments, the elastomer layer may comprise a water-swellable elastomer, SAP, and organic/inorganic salts. In one or more embodiments, the intermediate layer may comprise water-swellable elastomers that have repeated units of the same monomers or at least two different types of monomers in the chains. Non-limiting examples of such water-swellable elastomers may comprise nitrile or hydrogenated nitrile in their compositions. Incorporating SAP and/or organic or inorganic salts in the elastomer layer may enhance the capacity of water absorption into the elastomer matrix and therefore, may exhibit increased swelling behavior in a fluid.
In one or more embodiments, the intermediate layer may be swelled in a fluid by an absorption mechanism. For an example, the intermediate layer may have the property to soak up both hydrophilic and hydrophobic fluids. In one or more embodiments, uniform distribution of fluid in the swelled elastomer layer may take 2 to 3 days or more depending on the depth of a well. A plurality of fluid passages may be formed through the contractible tubing to provide a plurality of fluid access points to the intermediate layer and expedite the swelling process of a tubing in a fluid according to one or more embodiments. In order to ensure that swelling of the elastomer layer uniformly contracts the inner pipe, the number of fluid access points (via fluid passages) required may be pre-determined depending on the length of the contractible tubing.
In one or more embodiments, the intermediate layer may be swelled at a certain volume percentage of its original volume. The volume percentage swelling may be calculated by fraction volume occupied by the intermediate layer after swelling compared to the volume occupied by the intermediate layer before any swelling. The percent volume increase may range from 5 to 100% greater than the initial volume of the intermediate layer before swelling. For example, the percent swelling of the intermediate layer of the contractible production tubing may range from a lower limit of one of 5, 10, 20, 40, 60, 80, and 90% to an upper limit of one of 10, 20, 40, 60, 80, 90 and 100%, where any lower limit may be paired with any mathematically compatible upper limit. In one or more embodiments, the volume increase of the elastomer intermediate layer due to swelling or the expansion of the elastomer may be irreversible and predetermined as part of the design. In one or more embodiments, the intermediate layer may comprise an elastomer that occupies a volume percentage ranging from 50 to 100% greater than the volume of the intermediate layer immediately after construction and prior to any swelling. In one or more embodiments, a fully swollen intermediate layer may comprise an elastomer that occupies a volume that ranges between 90 and 100% greater than the volume of the intermediate layer prior to swelling (e.g., where the intermediate layer may swell up to double its initial unswollen volume).
In one or more embodiments, the intermediate layer may have Young's modulus values ranging from 0.1 Mpa to 10 Mpa. Young's modulus is a measure of the stiffness of an elastic material, and it is defined as the ratio of stress to strain. For example, the Young's modulus of the intermediate layer of the contractible production tubing may range from a lower limit of one of 0.1, 0.5, 1, 2, 5, 7, and 8 Mpa to an upper limit of one of 0.5, 1, 2, 5, 7, 8 and 10 Mpa, where any lower limit may be paired with any mathematically compatible upper limit.
In one or more embodiments, the swelling of the intermediate layer may depend on the environment, fluid chemistry, temperature, salinity, fluid viscosity, and the solubility parameter of the elastomer. The solubility parameter is defined as a thermodynamic property related to the energy of attraction between molecules. If both the elastomer and the surrounding fluid that it swells in have solubility parameters in a similar range, swelling may be high. In one or more embodiments, the swelling of the intermediate layer may decrease as the difference in solubility parameters of the elastomer layer and the fluid it swells in increase. Once swollen, the elastomer layer may not be changed back to its original volume by changing the fluid system.
In one or more embodiments, the intermediate layer may be swellable under a variety of liquids. Non-limiting examples of such fluids may be hydrocarbons, oils, and water. In one or more embodiments, the intermediate layer may be swellable under wide ranges of pressure and temperature, and the swelling of the intermediate layer may be independent of the pressure, the temperature, or both in the environment around the contractible tubing. In one or more embodiments, contractible tubing may be utilized (and the intermediate layer may be swellable) in environments having a pressure above 15,000 psi and a temperature above 400° F.
In one or more embodiments, the thickness of the intermediate layer before any swelling may be in a range from about 0.5 to 10 inches. For example, the thickness of the intermediate layer of contractible production tubing before any swelling may range from a lower limit of any one of 0.5, 1, 2, 5, 7, and 9 inches to an upper limit of any one of 1, 2, 5, 7, 9, and 10 inches, where any upper limit may be paired with any mathematically compatible lower limit. In one or more embodiments, the thickness of the intermediate elastomer after being fully swelled may be in a range from about 1 to 20 inches. For example, the thickness of the intermediate layer of contractible production tubing after being fully swelled may range from a lower limit of any one of 1, 2, 5, 7, 10, 13, 15, and 17 inches to an upper limit of any one of 5, 7, 10, 13, 15, 17, 19, and 20 inches, where any upper limit may be paired with any mathematically compatible lower limit.
In one or more embodiments, the thickness of the intermediate layer may be pre-designed and may be dependent on the tubing downsizing requirement in a well. For an example, if the tubing downsizing requirement is such that the inner diameter reduces from 7 inches to 4.5 inches, the thickness of the elastomer layer may need to be increased by 2.5 inches upon swelling. For another example, if the tubing downsizing requirement is such that the inner diameter reduces from 4.5 inches to 2.85 inches, the thickness of the elastomer layer may need to be increased by 1.65 inches upon swelling.
In one or more embodiments, the inner diameter of the contractible production tubing before any swelling may range from about 0.1 to 20 inches. As will be appreciated by those skilled in the art, the diameter of the contractible production tubing may be measured as the average diameter. In one or more embodiments, the inner diameter of the inner pipe after contraction may be reduced from 5 to 100% after swelling of the elastomer layer. For a non-limiting example, an elastomer may be selected that radially swells 5-10% (as measured along the thickness of the intermediate layer) upon contact with fluid. For another non-limiting example, an elastomer may be selected that radially swells 80-100% upon contact with fluid. The % swelling in a radial direction (along the thickness of the intermediate layer) may be dependent on a wide range of parameters including the elastomer material used in the intermediate layer, fluid pressure, duration of contact between the elastomer and fluid, and design of the contractible tubing.
In one or more embodiments, the ratio of the thickness of the elastomer layer and the thickness of the inner pipe before any swelling may range from 0.01 to 100.
Contractible tubing according to embodiments of the present disclosure may be constructed using a variety of methods. In one or more embodiments, the construction of the contractible tubing may include providing a hollow tubing with elastomers injected in the middle of the hollow section (e.g., where the elastomers may be flowed through the hollow section until the hollow section is substantially or entirely filled with the elastomers). In some embodiments, an elastomer layer may be provided as a pre-formed layer having a generally tubular shape, where the pre-formed elastomer layer may be concentrically slid between the inner pipe and the outer pipe.
A non-limiting example of a contractible tubing construction may include providing a first pipe with a fixed or rigid outer diameter, a pre-formed elastomer layer, and a second pipe having a contractible inner diameter, where the second pipe has dimensions that fit within the pre-formed elastomer layer, and the pre-formed elastomer layer has dimensions that fit within the first pipe. The pre-formed elastomer layer may be slid between the first and second pipes, such that the elastomer layer is layered between the inner layer of the first pipe and the outer layer of the second pipe.
In another non-limiting example, contractible tubing construction may include assembling two concentric pipes of two different inner diameters and adding an elastomer layer in between the two pipes such that the elastomer layer is filled in between the concentrically assembled inner pipe and outer pipe. The material of construction for two pipes as described may vary such that the pipe with a larger diameter may be rigid, and the pipe with a smaller diameter may be malleable and contractible under stress.
Additionally, contractible tubing may be designed based on the conditions in which the contractible tubing is deployed. For example, contractible tubing used for deployment as production tubing in a well may be designed based on the conditions of the well, which may be modeled prior to constructing the contractible production tubing. In some embodiments, contractible production tubing may be designed based on the predicted changes in reservoir pressure in a well. As hydrocarbons are extracted from a well, the reservoir pressure decreases, and therefore, the tubing size reduction requirement may be progressive over the life of a production operation from a well. By modeling the pressure losses encountered by a produced fluid from a reservoir as it flows from the formation to the surface, optimum tubing size may be determined.
To model an overall well performance, two model relationships are widely used—Vertical Lift Performance Relationship (VLP) and Inflow Performance Relationship (IPR) relationship. As used herein, VLP is defined as the bottom-hole pressure as a function of flow rate. The VLP depends on many factors including fluid pressure, volume, and temperature (PVT) properties, well depth, tubing size, surface pressure, water cut, and gas-oil ratio (GOR). It describes the flow from the bottom hole of the well to the wellhead. A VLP curve is a relationship between the flow rate and the pressure. The VLP curve shows how much pressure is required to lift a certain amount of fluid to the surface at the given wellhead pressure. As used herein, IPR is defined as the well-flowing bottom-hole pressure (Pwf) as a function of production rate. It describes the flow in the reservoir. The Pwf is defined in the pressure range between the average reservoir pressure and atmospheric pressure. IPR may be defined using the following equations:
Both the IPR and the VLP relate the wellbore flowing pressure to the surface production rate. While the IPR represents what the reservoir can deliver to the bottom hole, the VLP represents what the well can deliver to the surface. The intersection of the IPR curve with the VLP curve on a wellbore flowing pressure vs fluid flow rate plot is called an operating point. As used herein, the term “operating point” refers to the well deliverability, an expression of what a well will actually produce for a given operating condition (Pr, PI, WC, GOR, THP, tubing size, etc.). At any random time, the operating point may be at a specific condition, and from one time to another in the life of an oil or gas production operation, the operating point may vary depending on the operating conditions. Once an operating point is determined from the well modeling, the hydrocarbon production operation may be conducted at that specific wellbore flowing pressure and fluid flow rate. Therefore, contractible production tubing may be designed based on the wellbore-flowing pressure required to achieve the desired fluid flow rate under the operating conditions. For example, various design parameters of the contractible production tubing, such as the inner diameter, outer diameter, thickness of the intermediate layer, and composition of the elastomer layer in order to ensure swelling to an extent that achieves desired inner diameter of the contractible production tubing, may be selected to achieve a desired fluid flow rate under different operating conditions in a well.
Embodiments disclosed herein also relate to methods of using contractible production tubing. For example, methods of using contractible production tubing according to embodiments of the present disclosure may include reducing a production tubing size to a smaller size by hydraulically enlarging a swellable elastomer inside the contractible production tubing, e.g., swelling an elastomer intermediate layer of a contractible tubing in the presence of fluids such as water and hydrocarbons to reduce the tubing inner diameter.
As shown in
In one or more embodiments, the decrease in the inner diameter of the contractible production tubing upon swelling of the intermediate layer may help maintain a lower critical rate to lift liquid from the well to the surface.
In one or more embodiments, the time for expansion and tubing downsizing may be determined based on the production profile of an individual well and an expansion ratio of the swellable elastomers.
In one or more embodiments, contractible production tubing may be utilized to downsize the tubing sizes required during the production phase of a gas well. In one or more embodiments, the change of an inner diameter of the contractible production tubing may be referred to as downsizing. Non-limiting downsizing examples in accordance with one or more embodiments include downsizing a contractible production tubing from having an inner diameter of 7 inches to 4.5 inches, or from 4.5 inches to 3.5 inches, or from 4.5 inches to 2.875 inches, or from 2 inches to 0.375 inches.
Accordingly, one or more embodiments of the present disclosure may be used to overcome challenges with decreasing reservoir pressure in a well, as well as provide additional advantages over conventional methods, as will be apparent to one of ordinary skill. Introducing a contractible production tubing may eliminate or reduce the need for changing out tubing to smaller sizes during wellbore operations, and therefore, the downtimes of a well may be reduced by utilizing a contractible production tubing. may significantly reduce liquid loading. A small decrease in the inner diameter of the contractible production tubing (e.g., as little as a 5-10% decrease) may result in a significant increase in the production fluid pressure, and therefore, may improve the overall efficiency of an operation. A contractible production tubing may also improve the gas recovery factor in the gas field and keep the gas well flowing for a long period of time when in comparison to conventional methods and reduce liquid loading. Further, the intermediate elastomers layers in a contractible production tubing may also prevent or reduce the chance of having tubing leakage.
While the present disclosure has been described with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the disclosure as described herein. Accordingly, the scope of the disclosure should be limited only by the attached claims.
