CA2860186C - Controlling a flow of fluid and distributing fluid - Google Patents

Abstract

Systems and methods for controlling a flow of fluid through an orifice in a flow control device. The systems and methods may include applying an erosion and/or corrosion resistant layer on a surface of the flow control device around an opening of the orifice for reducing or preventing erosion and/or corrosion and for maintaining a size of the opening.

Description

CONTROLLING A FLOW OF FLUID AND DISTRIBUTING FLUID
FIELD
[0001] The disclosure relates generally to systems and methods for controlling a flow of fluid and for distributing fluid. More specifically, the disclosure relates to methods and systems of controlling the flow of fluid and for distributing fluids while reducing and/or preventing erosion and/or corrosion in a flow control device.
BACKGROUND

[0002] There are many hydrocarbon bearing formations having reservoirs that contain high viscosity heavy oil. A variety of methods have been proposed for recovering hydrocarbons from these formations by increasing the mobility of the heavy oil. Such methods include thermal stimulation processes, which include but are not limited to cyclic steam stimulation (CSS), steam flood (SF), and steam assisted gravity drainage (SAGD).
Generally speaking, the thermal stimulation processes use steam and/or other gases to heat and mobilize the heavy oil in the reservoir and the mobilized heavy oil is recovered from the reservoir.

[0003] In CSS, steam is injected through an injection well into the hydrocarbon bearing formation. The injection well is shut in so that the steam soaks in and heat is transferred to the hydrocarbon bearing formation to lower the viscosity of the heavy oil. In SF, steam is injected into the hydrocarbon bearing formation through an injection well. Steam moves through the hydrocarbon bearing formation, mobilizing oil as it flows toward the production well. In SAGD, steam is injected into the hydrocarbon bearing formation through an injection well at a rate which is able to maintain a near constant operating pressure in a steam chamber in the hydrocarbon bearing formation.

[0004] One concern in all thermal stimulation processes is the distribution of fluid, such as steam or other gases, from horizontal wells into the hydrocarbon bearing formation.
Distribution of fluid is accomplished in conventional techniques by providing holes or slots in the casing. In a horizontal well used for fluid injection, fluid distribution can be achieved by limiting the number and size of holes in a base pipe or liner so that at the desired injection rates, the pressure drop through the hole in the base pipe is greater than the pressure drop along the length of the base pipe and equitable fluid distribution at each of the hole locations is achieved. Thus, the pressure gradients available for fluid flow between the pipe and reservoir at all points on the horizontal well are essentially the same. In a horizontal well used for production, distribution of production can be optimized in a similar way ¨ the number and size of holes in the base pipe or liner can be limited so that at the desired production rates, the pressure drop through the holes is greater than the pressure drop along the length of the base pipe and equitable fluid distribution at each hole location may be achieved.

[0005] One example is set out in CA 2,219,513 which uses an enhanced steam distribution method. The production phase is the phase where material, such as but not limited to hydrocarbons, is produced from the subterranean formation. In contrast, an injection phase is the phase where fluid is injected into the subterranean formation. For horizontal wells, a reduced number and size of holes is desirable to increase the pressure drop through each hole to achieve more equitable production along the length of the horizontal well. In this enhanced recovery method, the number of orifices in the base pipe is reduced, as compared with conventional techniques, to increase the pressure drop across the orifices. The base pipe may have a collar around a portion with a sand control device connected to the collar. The sand control device may be over a portion of the base pipe. The collar may be over at least one of the orifices. The collar may be spaced from the base pipe to provide an annulus. The collar and sand control device allow the steam to exit uniformly across the sand control device into the reservoir during steam injection, and during production allow produced fluids from the reservoir to enter through the sand control device along the annulus between the collar and the base pipe and through the orifices. The collar may have material properties and a wall thickness which can withstand the force and erosional effects of the high velocity flow near the orifice.

[0006] Flow control devices may be used to control flow rates across the length of a well. These flow control devices may control both the injection of fluids into the formation and the production of fluids from the formation into the well. The flow control devices have orifices. The diameter of the orifices is selected to provide the desired flow rate and distribution of flow along the length of the well. In the flow control devices, the orifices are susceptible to flow-induced erosion. The erosion changes the size of the orifice which will change the flow rates.

[0007] In many of the conventional systems, the orifices are designed to create a high pressure drop across the orifice for injected or produced fluids. The design may cause =
erosion of the orifices. The erosion can cause the orifices to become larger.
For efficient recovery, the distribution of injected and produced fluids may be controlled by the size of the orifice and therefore erosion of the orifice should be avoided.

[0008] Although it would be preferable to use components made from a material that is erosion resistant, there are technical limitations and the costs are prohibitive. Erosion resistant materials, such as tungsten carbide, are very expensive in comparison with steel as a material of fabrication. It is also too expensive to coat all surfaces of equipment in a protective coating.

[0009] U.S. Patent Publication 2008/0251255 discloses a flow control device where a nozzle is used in an orifice to control the flow of fluids into the wellbore.
The nozzle may be made from an erosion resistant material. The nozzle that forms the orifice to control the flow rate is generally press fit into a larger hole drilled in the casing or housing. This system has the disadvantage that, during operation, the nozzle may be dislodged from the hole. For example, differential thermal expansion when the well is heated or cooled during steaming operations or production may cause the nozzle to become loose, and differential pressure across the nozzle will cause it to become dislodged from the hole. When the nozzle is dislodged, the size of the orifice is significantly altered, resulting in a loss of fluid flow control.
The dislodged nozzle may also interfere with other parts of the system and therefore affect injection and/or production.

[0010] Other types of flow control devices mitigate erosion and corrosion by using long, tortuous flow paths or opposing jets to avoid high velocity flows from impinging directly on the surfaces of a component. Long flow paths are subject to plugging.
Opposing jets have been used in production only for flow control devices but have limited effectiveness in reducing contact on the surface by the high velocity flow. As a result, these options are not as effective solutions.

[0011] Corrosion is also an issue. When using flow control devices that use high velocity flow, the high velocity flow can result in accelerated local corrosion on the base pipe and other components in the assembly. Base pipes and other equipment used in oil and gas reservoirs are commonly made from steel. This equipment is subject to corrosion from the produced fluids, steam, water, and combustion gases such as oxygen and carbon dioxide, present in the pipes and reservoirs. Corrosion may affect the size of the orifices and reduce the life and effectiveness of the equipment and therefore is a concern.

[0012] In view of the above, it is desirable to provide methods and systems of controlling the flow of fluid and for distributing fluids while reducing and/or preventing erosion and/or corrosion in a flow control device.
SUMMARY

[0013] The present disclosure provides a method for controlling a flow of fluid through an orifice in a flow control device subject to erosion or corrosion that comprises applying an erosion and/or corrosion resistant layer on a surface of the flow control device around an opening of the orifice for reducing or preventing erosion and/or corrosion and for maintaining a size of the opening.

[0014] The present disclosure provides a flow control device for controlling a flow of fluid in a well in a subterranean reservoir that comprises one or more orifices for controlling the flow of fluid in the well and an erosion and/or corrosion resistant layer on a surface of the flow control device around an opening of the one or more orifices for reducing or preventing erosion and/or corrosion and for maintaining a size of the opening.

[0015] The present disclosure provides a system for distributing fluid in a fluid injection phase or a fluid production phase in a subterranean reservoir that comprises a base pipe having spaced apart orifices in a wall of the base pipe and an erosion and/or corrosion resistant layer on a surface of the base pipe around an opening of one or more of the spaced apart orifices for reducing and/or preventing erosion and/or corrosion and maintaining a size of the opening. The spaced apart orifices represent an open area in the base pipe of less than 0.2%. Fluid flowing through the base pipe flows outwardly through the spaced apart orifices and is distributed outwardly to the subterranean reservoir during the fluid injection phase or fluid flowing from the subterranean reservoir to the well flows inwardly through the spaced apart orifices to the base pipe during the production phase.

[0016] The present disclosure provides a method for distributing fluid into a well in a subterranean reservoir that comprises providing, in the subterranean reservoir, a base pipe having spaced apart orifices along the length of the base pipe and an erosion and/or corrosion resistant layer on a surface around the opening of one or more of the orifices; and injecting fluid into the base pipe, such that the fluid flows outwardly from the orifices to the subterranean reservoir, and/or producing fluid from the subterranean reservoir so that the fluid flows inwardly from the subterranean reservoir through the orifices to the base pipe.

The orifices represent an open area in the base pipe of less than 0.2%. The erosion and/or corrosion resistant layer reduces or prevents erosion and/or corrosion and maintains a size of the opening.

[0017] The foregoing has broadly outlined the features of the disclosure so that the detailed description that follows may be better understood. Additional features will also be described herein.
BRIEF DESCRIPTION OF THE DRAWINGS

[0018] These and other features, aspects and advantages of the present disclosure will become apparent from the following description and the accompanying drawings, which are described briefly below.

[0019] Fig. 1 and 2 are flow charts setting out two aspects of the present disclosure.

[0020] Fig. 3 is a section view of a standard tubing conveyed configuration in a reservoir with a well having flow control devices.

[0021] Fig. 4 is a section view of a standard liner conveyed configuration for a well in a reservoir with multiple flow control devices with sand screens.

[0022] Fig. 5 is a section view of a base pipe with a flow control device with a radial orifice, housing and sand screen.

[0023] Fig. 6 is a side elevation view of a base pipe with a collar and wire wrap screen.

[0024] Fig. 7 is a cross sectional view of the base pipe and collar in Figure 4.

[0025] Fig. 8 is a section view of a flow control device with an axial orifice.

[0026] It should be noted that the figures are merely examples and that no limitations on the scope of the present disclosure are intended hereby. Further, the figures are generally not drawn to scale but are drafted for the purpose of convenience and clarity in illustrating various aspects of the disclosure.
DETAILED DESCRIPTION

[0027] For the purpose of promoting an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the disclosure is thereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein are contemplated as would normally occur to one skilled in the art to which the disclosure relates. It will be apparent to those skilled in the relevant art that some features that are relevant to the present disclosure may not be shown in the drawings for the sake of clarity.

[0028] At the outset, for ease of reference, certain terms used in this application and their meanings as used in this context are set forth below. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present processes are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments and terms or processes that serve the same or a similar purpose are considered to be within the scope of the present disclosure.

[0029] As used herein, the term "hydrocarbon" refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon.
Hydrocarbons may also include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons generally fall into two classes:
aliphatic, or straight chain hydrocarbons, and cyclic, or closed ring hydrocarbons, including cyclic terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, oil, coal, heavy oil and kerogen that can be used as a fuel or upgraded into a fuel.

[0030] As used herein, the terms "produced fluids" and "production fluids" refer to liquids and/or gases removed from a subsurface formation, including, for example, an organic-rich rock formation. Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids. Production fluids may include, but are not limited to, liquids and/or gases originating from pyrolysis of oil shale, natural gas, synthesis gas, a pyrolysis product of coal, carbon dioxide, hydrogen sulfide and water (including steam).

[0031] As used herein, the term "fluid" refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and solids, and combinations of liquids and solids.

[0032] As used herein, the term "formation hydrocarbons" refers to both light and/or heavy hydrocarbons and solid hydrocarbons that are contained in an organic-rich rock formation. Formation hydrocarbons may be, but are not limited to, natural gas, oil, kerogen, oil shale, coal, tar, natural mineral waxes, and asphaltenes.

[0033] As used herein, "reservoir" or "subterranean reservoir" is a subsurface rock or sand formation from which a production fluid or resource can be harvested. The rock formation may include sand, granite, silica, carbonates, clays, and organic matter, such as oil shale, light or heavy oil, gas, or coal, among others. Reservoirs can vary in thickness from less than one foot (0.3048 meter (m)) to hundreds of feet (hundreds of meters).

[0034] As used herein "subsurface formation" or "subterranean formation"
or "hydrocarbon bearing formation" or "formation" refers to the material existing below the Earth's surface. The subsurface formation may interchangeably be referred to as a formation or a subterranean formation. The subsurface formation may comprise a range of components, e.g. minerals such as quartz, siliceous materials such as sand and clays, as well as the oil and/or gas that is extracted.

[0035] As used herein, "substantial," "about" and "approximate" when used in reference to a quantity or amount of a material, or a specific characteristic of the material, refers to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may in some cases depend on the specific context.

[0036] As used herein, "wellbore" is a hole in the subsurface formation made by drilling or inserting a conduit into the subsurface. A wellbore may have a substantially circular cross section or any other cross-section shape, such as an oval, square, rectangle, triangle, or other regular or irregular shapes. The term "well", when referring to an opening in the formation, may be used interchangeably with the term "wellbore". Further, multiple pipes may be inserted into a single wellbore, for example, as a scab liner or tubing configured to allow flow from an outer chamber to an inner chamber.

[0037] The articles "the", "a" and "an" are not necessarily limited to mean only one, but rather are inclusive and open ended so as to include, optionally, multiple such elements.

[0038] "At least one," in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase "at least one"
refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, "at least one of A and B" (or, equivalently, "at least one of A or B," or, equivalently "at least one of A and/or B") may refer, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases "at least one," "one or more," and "and/or" are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions "at least one of A, B and C," "at least one of A, B, or C," "one or more of A, B, and C," "one or more of A, B, or C" and "A, B, and/or C" may mean A alone, B alone, C alone, A and B
together, A
and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.

[0039] Generally, the present disclosure provides methods and systems for reducing and/or preventing erosion and/or corrosion in flow control devices used in hydrocarbon recovery and, in one aspect, in wellbores. The present system comprises an erosion and/or corrosion resistant coating or layer applied to equipment and, in one aspect, to the outer surface defining an orifice. The erosion and/or corrosion resistant coating or layer is applied to the outer surface around the orifice to maintain an opening size of the orifice.

[0040] As set out in Figure 1, the methods may comprise the step 2 of providing a flow control device for use in a well for recovery of hydrocarbons. The methods may comprise the step 4 of applying an erosion and/or corrosion resistant coating or layer on a surface of the flow control device. The erosion and/or corrosion resistant coating or layer may be applied to the surface around an orifice in the flow control device to maintain the opening size of the orifice. With the layer in place, erosion of the material in the orifice, other than the erosion and/or corrosion resistant coating or layer, may not alter the size of the orifice and therefore fluid flow control may be maintained.

[0041] The erosion and/or corrosion resistant coating or layer may be applied only to the outer surface of the equipment in the area immediately around the opening of the orifice.
It is not necessary to apply the erosion and/or resistant coating or layer to the entire exposed surface of the equipment or to the entire exposed surface of the orifice.
During use, the material defining the orifice may become eroded. However, the erosion and/or corrosion resistant coating or layer applied to the outer surface around the opening of the orifice may continue to maintain and define the opening size of the orifice, thereby maintaining fluid flow control.

[0042] The system and method provides for substantial reduction or prevention of erosion but is less expensive than coating all exposed surfaces of the equipment. As set out above, the system and method is more reliable, especially for thermal operations, than insert nozzles which may become dislodged. If desired, the entire surface of the orifice may be coated with the erosion and/or corrosion resistant coating or layer, including the inner surface of the equipment around the inner opening of the orifice and/or the sides of the orifice.
Additional portions of the equipment surface may be coated with the erosion and/or corrosion resistant coating or layer. The terms erosion and/or corrosion resistant coating and erosion and/or corrosion resistant layer are used interchangeably herein and include one or more layers of the erosion and/or corrosion resistant material.

[0043] The erosion and/or corrosion resistant coating or layer may be known as a hardfacing, a hardface layer, a hardface coating or a cladding.

[0044] The present methods and systems may be used with conventional or other enhanced recovery processes for the recovery of hydrocarbons from formations, such as but not limited to water flood, polymer flood, and gas flood processes. The present methods and systems may be suitable for use with thermal recovery processes, such as but not limited to CSS, SF, and SAGD, including the use of solvents. The present methods and systems may be used in formations with conventional oil or heavy oil. The present methods and systems may be used in formations with heavy oil and/or bitumen.

[0045] The present methods and systems may be used for the maintenance of the orifices in flow control devices. Flow control devices provide a restriction in the flow path of a fluid to create a desired flow rate pressure drop relationship. The restriction in each flow control device may be a plurality of orifices, nozzles, tubes, long flow path, or other suitable ways to provide the restrictions. Flow control devices may control fluid flow in the injection phase for fluid injected from the well into the formation. Flow control devices may control fluid flow in the production phase for fluid flow from the formation into the well.
Flow control devices are commercially available and include for example ResflowTM and ReslnjectTM from Schlumberger Limited, BHI Equalizer from Baker Hughes, FloReg from Weatherford, and Inject-CheckTm from Halliburton. Examples of flow control devices are also shown in U.S.
Patent 8,312,931; U.S. Publication 2008/0314590; U.S. Publication 2007/0272408; U.S.

Publication 2007/0246210; U.S. Patent 6,622,794; U.S. Patent 6,516,888; U.S.
Patent 6,505,682 and U.S. Patent 6,371,210. Flow control devices may include base pipes having a selected number and size of holes, for example as set out above in CA
2,219,513. The methods and systems may be described below in relation to pipes or base pipes, which are commonly referred to as casing, liner, tubing, scab liner, and completion string, but are not limited to them and may include any flow control device.

[0046] The flow control devices may be used to control the flow of fluids in the well.
The control may include the flow of fluids injected from the well into the formation, such as but not limited to steam, solvent, or other gases. The control may include the flow of fluids produced from the formation into the well, such as but not limited to liquid hydrocarbons.

[0047] As set out in Figure 2, the method may include the step 6 of providing in a subterranean reservoir a base pipe having orifices in the base pipe . The base pipe may be provided in a well within the subterranean reservoir. The orifices may be for fluid flow. The base pipe may have an erosion and/or corrosion resistant layer on a surface of the base pipe around the opening of one or more of the orifices. The orifices may represent an open area in the base pipe of less than 0.2%. The method may include injecting 8 fluid into the base pipe such that the fluid flows outwardly from the orifices to the reservoir.
The method may include producing 10 fluid from the subterranean reservoir so that fluid flows inwardly from the subterranean reservoir through the orifices to the base pipe. The erosion and/or corrosion resistant layer may reduce or prevent erosion and/or corrosion and maintain a size of the opening.

[0048] The orifices may be in the wall of the base pipe. The base pipe may include housing sections around at least a portion of the base pipe and at least a portion of the orifices are between a wall of the base pipe and the housing sections. The housing sections may be configured to distribute the fluid in the fluid injection phase and/or minimize the influx of particulate matter in the production phase. Each of the housing sections may be over at least one orifice. The housing may include a protective layer. The protective layer may be the erosion and/or corrosion resistant material and may be on a portion of the housing subject to the fluid injection to reduce or prevent erosion of the housing. As a result, the housing may be made from a low-cost steel and/or have a reduced wall thickness.

[0049] Figure 3 shows a standard tubing conveyed well configurations in a reservoir where the well includes flow control devices. Figure 3 shows a well 100 having production tubing 101 and creating an annulus between the tubing and the well casing 105.
In this configuration, the well 100 includes packers 102 isolating sections of the well 100 and flow control devices 103 in between the packers 102. Shown in this figure, the packers 102 and flow control devices 103 are installed on the production tubing 101. Flow control devices may be installed without packers. Production tubing may be run to surface as shown, or may be hung lower in the well as a scab liner. Perforations 104, slots, or screens are present in the casing 105 to allow flow between the flow control devices and the reservoir.
Two isolated sections having flow control devices are shown in Figure 3. However, the length of the well may include any number of isolated sections and flow control devices, as required for injection and/or production.

[0050] Figure 4 shows a standard liner deployed well configuration in a reservoir where the well includes flow control devices. In this configuration, the production and/or injection string is in the casing 105. Packers 102 may be used in the annulus between the casing and the formation to isolate sections of the well. Flow control devices 103 are positioned in the isolated sections of the well. The flow control devices may include sand screens 106. The casing may continue to surface as shown in the figure or be hung as a liner.

[0051] Figure 5 shows a base pipe 1 having a housing 5 over an orifice 7 in the base pipe. A fluid is injected from the base pipe through the orifice, through the annulus between the housing and the outer surface of the base pipe, and into the reservoir through the sand screen 3. Fluid may be produced from the reservoir, through the sand screen, through the orifice 7 and into the base pipe. The fluid flow in both directions is shown by arrows 13. The erosion resistant layer 11 is applied to the outer surface of the base pipe around the opening of the orifice 7. The erosion resistant layer 11 may be applied to the inner surface of the base pipe around the orifice (not shown), instead of or in addition to the layer on the outer surface of the base pipe. A protective layer 12, of the same or different erosion resistant material, may be applied to the housing at a position which is subjected to the fluid injection from the orifice 7. Although Figure 5 shows the housing and sand screen, these features may not be present, depending on the requirements of the particular reservoir. The sand screen may be any sand control device or distribution element that is configured to distribute fluids in the injection phase and minimize the influx of particulate matter in a production phase. For example, the sand screen may be a sand control or distribution element that comprises, but is not limited to, a wire wrapped screen, slotted liner, woven mesh, and/or steel wool.

[0052] Figures 6 and 7 show a portion of one system for controlling the flow rate of fluid injection from a base pipe into a reservoir. This system is described in more detail in CA
2,219,513. A base pipe 1 for a well includes a number of orifices in it for injection of steam and other fluids into a reservoir. The number, placement, and size of the orifices are selected to control the flow rate of the fluid through the base pipe and along the length of the well. The base pipe is shown in Figures 6 and 7 with a sand screen 3 and housing 5 extending around the outside of portions of the base pipe. Figure 7 show rods 14 spacing the housing 5 from the base pipe 1 but these are optional depending on the specific configuration. The housing is positioned over one or more orifices. One orifice 7 is shown in Figure 5.
Steam or other fluid is injected through the orifice 7, passes through the sand screen 3, and enters the reservoir. In another aspect of this system, not shown in the figures, the housing 5 is not present. As well, as set out above, any sand control device may be used or no sand control device may be used, depending on the specific requirements of a particular reservoir. Figure 6 shows the sand screen on both sides of the orifice; however this is not essential; the sand screen may be located on only one side of the orifice.

[0053] In Figures 5 to 8, the size of the orifices is selected in order to control the flow rate of the fluid along the length of the well. As a result, the orifices tend to be small.
Therefore, the flow velocity through the orifices tends to be high, and erosion or accelerated corrosion of the base pipe may occur. It is important to maintain the size of the orifice constant over the life of the base pipe. Erosion of the sides of the orifice will enlarge the orifice and affect the flow rate of the fluid which affects the efficiency of the hydrocarbon recovery along the length of the well.

[0054] An erosion resistant layer 11 may be on the surface of the base pipe around the orifice to define its opening. The erosion resistant layer 11 may be applied by welding methods. The erosion resistant layer 11 may be deposited in any manner known in the art, such as a thermal spray or known surface treatments. The erosion resistant layer 11 may define the opening of the orifice so that if the material in the base pipe 1 defining the orifice is eroded, the size of the orifice remains substantially constant as a result of the erosion resistant coating or layer. The opening in the erosion resistant layer 11 may be larger or smaller than the opening in the base pipe due to the manufacturing constraints.

[0055] A protective coating or layer 12 of the same or different erosion resistant material as the erosion resistant layer may be deposited on the housing. The protective coating or layer 12, as shown in Figures 5 or 8, may be at a position corresponding to the injection point from the orifice. This protective coating or layer 12 may protect the housing from erosion as a result of the injection through the orifice of steam or other fluids which may contact the corresponding portion of the housing at high velocity.

[0056] Figure 8 shows a base pipe 1 with a housing 5. The base pipe has an opening 9 for the passage of fluids from the base pipe to the housing and into the reservoir. Fluid flow is shown by arrows 13. An orifice 7 is between the outside surface of the base pipe 1 and the housing 5. The base pipe would include multiple openings and corresponding orifices distributed along the length of the pipe to control the flow rate of the fluid injected into a reservoir but only one opening and corresponding orifice is shown in the figure. The opening 9 is relatively large as compared to the size of orifice 7 and does not control the flow rate of the fluids. It is orifice 7 that is sized to control the flow rate of the fluid into the reservoir. As a result, the erosion resistant coating or layer 11 is applied on the outer surface of the orifice 7 around its opening to maintain the size of the opening of the orifice. The erosion resistant coating or layer may be applied on the inner surface of the orifice around the opening of the orifice 7 to maintain its size. The protective coating or layer 12 may be applied on the inner wall of the housing 5 and the outer wall of the base pipe 1 to prevent or reduce erosion due to the high velocity flow of fluids through the orifice 7. The protective coating or layer 12 may be applied on the downstream side of the orifice. For example, in a flow control device for injection only, the protective coating or layer may be applied only on the reservoir side of the orifice. In a flow control device for production only, the protective coating or layer may be placed between the orifice 7 and the opening 9. On a dual purpose injection and production flow control device, the layers may be disposed on both sides of the orifice.

[0057] Figures 5 to 8 show orifices in base pipes for the recovery of hydrocarbons from reservoirs using thermal recovery processes. However, the present systems and methods may be used with any flow control device and is not limited only to base pipes. The present systems and methods may be used in other equipment using sized orifices to control the flow rate of fluid where erosion and/or corrosion is an issue. This may include for example hydrocarbon processing equipment.

[0058] The erosion resistant layer 11 that is applied to the surfaces adjacent to and forming the opening of the orifice may be applied in any manner known in the art. The erosion resistant layer 11 may be applied by welding methods such as a welding arc overlay.
The erosion resistant layer 11 may be applied by brazing techniques. The erosion resistant layer 11 may be deposited by any known method such as a thermal spray. The protective coating or layer 12 may be applied to the surfaces in a manner similar to that of the erosion resistant layer 11.

[0059] The erosion resistant layer 11 may be corrosion resistant. The present systems and methods described above can use a corrosion resistant coating or layer, which may optionally be erosion resistant, in place of the erosion resistant layer.
The corrosion resistant coating or layer is positioned the same as the erosion resistant layer. Corrosion of metal pipes and other equipment in a well bore can cause the life of the equipment to be reduced. Corrosion can also plug the orifices or change their size which affects flow rate of the fluids being injected into the reservoir. A corrosion resistant layer may prolong the life of the equipment and size of the orifice, thereby maintaining the desired fluid flow rate.

[0060] The erosion and/or corrosion resistant layer can be any known material that is erosion and/or corrosion resistant. When the layer is connected to the base pipe or other metal equipment, it may comprise a material that does not have a cathodic potential relative to the base pipe or other metal equipment. Typical metal alloys that may be employed are based on nickel, cobalt, or chromium alloyed with molybdenum, tungsten, copper, manganese, vanadium, iron, silicon, carbon, nitrogen and others. In one aspect, the layer is made from a metal alloy such as stellite. In another aspect, the layer is made from is a composite that utilizes a metal alloy matrix with particles of ceramic, cermet, tungsten carbide, silicon carbide, or boron carbide.

[0061] Disclosed aspects of the present disclosure may be used in hydrocarbon management activities. "Hydrocarbon management" or "managing hydrocarbons" may include hydrocarbon extraction, hydrocarbon production, hydrocarbon exploration, identifying potential hydrocarbon resources, identifying well locations, determining well injection and/or extraction rates, identifying reservoir connectivity, acquiring, disposing of and/ or abandoning hydrocarbon resources, reviewing prior hydrocarbon management decisions, and any other hydrocarbon-related acts or activities. The term "hydrocarbon management" may be used for the injection or storage of hydrocarbons or CO2, for example the sequestration of CO2, such as reservoir evaluation, development planning, and reservoir management. The disclosed methodologies and techniques may be used to extract hydrocarbons from a subsurface region. Hydrocarbon extraction may be conducted to remove hydrocarbons from the subsurface region, which may be accomplished by drilling a well using oil drilling equipment.
The equipment and techniques used to drill a well and/or extract the hydrocarbons are well known by those skilled in the relevant art. Other hydrocarbon extraction activities and, more generally, other hydrocarbon management activities, may be performed according to known principles.

[0062] It should be noted that the orientation of various elements may differ, and that such variations are intended to be encompassed by the present disclosure. It is recognized that features of the disclosure may be incorporated into other examples.

[0063] It should be understood that the preceding is merely a detailed description of this disclosure and that numerous changes, modifications, and alternatives can be made in accordance with the disclosure here without departing from the scope of the disclosure. The preceding description, therefore, is not meant to limit the scope of the disclosure. Rather, the scope of the disclosure is to be determined only by the appended claims and their equivalents. It is also contemplated that structures and features embodied in the present examples can be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other.

Claims (29)

CLAIMS:

1. A method for controlling a flow of fluid through an orifice in a flow control device subject to erosion or corrosion, comprising applying an erosion and/or corrosion resistant layer on a surface of the flow control device around an opening of the orifice, for reducing or preventing erosion and/or corrosion and for maintaining a size of the opening;
wherein the erosion and/or corrosion resistant layer comprises a metal alloy.

2. The method of claim 1, wherein the flow control device is used in a recovery of hydrocarbons from a subterranean reservoir.

3. The method of claim 1 or 2, wherein the erosion and/or corrosion resistant layer is applied to the flow control device by welding the erosion and/or corrosion resistant layer to the surface around the orifice,

4. The method of claim 1 or 2, wherein the erosion and/or corrosion resistant layer is applied to the flow control device by thermal spray or surface treatment.

5. The method of any one of claims 1 to 4, wherein the erosion and/or corrosion resistant layer is comprised of a metal alloy matrix and particles of ceramic, cermet, tungsten carbide, silicon carbide, or boron carbide.

6 The method of claim 5, wherein the particles are tungsten carbide,

7. A flow control device for controlling a flow of fluid in a well in a subterranean reservoir, the flow control device comprising one or more orifices for controlling the flow of fluid in the well and an erosion and/or corrosion resistant layer on a surface of the flow control device around an opening of the one or more orifices, for reducing or preventing erosion and/or corrosion and for maintaining a size of the opening;
wherein the erosion and/or corrosion resistant layer comprises a metal alloy.

8. The flow control device of claim 7, wherein the flow control device controls the flow of fluid during injection of fluid into the subterranean reservoir.

9. The flow control device of claim 7 or 8, wherein the flow control device controls the flow of fluid during production of hydrocarbons from the subterranean reservoir into the well.

10. The flow control device of any one of claims 7 to 9, wherein the erosion and/or corrosion resistant layer is applied to the surface by welding the erosion and/or corrosion resistant layer to the surface.

11. The flow control device of any one of claims 7 to 9, wherein the erosion and/or corrosion resistant layer is applied to the surface by thermal spray or surface treatment.

12. The flow control device of any one of claims 7 to 11, wherein the erosion and/or corrosion resistant layer is comprised of a metal alloy matrix and particles of ceramic, cermet, tungsten carbide, silicon carbide, or boron carbide.

13. The flow control device of claim 12, wherein the particles are tungsten carbide.

14. The flow control device of any one of claims 7 to 13, further comprising a housing over at least one of the one or more orifices.

15. The flow control device of claim 14, wherein the housing comprises a protective layer applied to a portion of the housing over the at least one of the one or more orifices.

16. A system for distributing fluid in a fluid injection phase or a fluid production phase in a subterranean reservoir, comprising:
a. a base pipe having spaced apart orifices in the base pipe, wherein the spaced apart orifices represent an open area in the base pipe of less than 0.2%; and b. an erosion and/or corrosion resistant layer on a surface around an opening of one or more of the spaced apart orifices for reducing and/or preventing erosion and/or corrosion and maintaining a size of the opening, wherein the erosion and/or corrosion resistant layer comprises a metal alloy;
whereby fluid flowing through the base pipe flows outwardly through the spaced apart orifices and is distributed outwardly to the subterranean reservoir during the fluid injection phase or fluid flowing from the subterranean reservoir flows inwardly through the spaced apart orifices and is distributed inwardly to the base pipe during the production phase,

17. The system of claim 16, wherein the spaced apart orifices are in a wall of the base pipe.

18. The system of claim 16, wherein the spaced apart orifices are between a wall of the base pipe and housing sections around at least a portion of the base pipe.

19. The system of claim 16, further comprising housing sections around at least a portion of the base pipe, each of the housing sections configured to distribute fluid in the fluid injection phase and/or minimize influx of particulate matter in the fluid production phase; and each of the housing sections being around the base pipe such that at least a portion of each of the housing sections is over at least one of the spaced apart orifices.

20. The system of any one of claims 16 to 19, wherein the erosion and/or corrosion resistant layer is comprised of a metal alloy matrix and particles of ceramic, cermet, tungsten carbide, silicon carbide, or boron carbide.

21. The system of claim 20, wherein the particles are tungsten carbide.

22. The system of claim 19, wherein one or more of the housing sections comprises a protective layer applied to a portion of the one or more housing sections over the at least one of the spaced apart orifices.

23. A method for distributing fluid into a well in a subterranean reservoir, comprising the steps of:
a. providing, in the subterranean reservoir, a base pipe having orifices in the base pipe, wherein the orifices represent an open area in the base pipe of less than 0.2%, and an erosion and/or corrosion resistant layer on a surface around an opening of one or more of the orifices, wherein the erosion and/or corrosion resistant layer comprises a metal alloy;
b. injecting fluid into the base pipe, such that the fluid flows outwardly from the orifices to the subterranean reservoir, and/or producing fluid from the subterranean reservoir so that the fluid flows inwardly from the subterranean reservoir through the orifices to the base pipe;
wherein the erosion and/or corrosion resistant layer reduces or prevents erosion and/or corrosion and maintains a size of the opening.

24. The method of claim 23, wherein the orifices are in a wall of the base pipe.

25. The method of claim 23, wherein at least a portion of the orifices are between a wall of the base pipe and housing sections around at least a portion of the base pipe.

26. The method of claim 23, further comprising housing sections around at least a portion of the base pipe, wherein each of the housing sections is configured to distribute the fluid in the fluid injection phase and/or minimize influx of particulate matter in the production phase, and each of the housing sections is over at least one of the orifices.

27. The method of claim 26, wherein the housing sections comprise a protective layer applied to a portion of the housing sections over the at least one of the orifices.

28. The method of any one of claims 23 to 27, wherein the erosion and/or corrosion resistant layer is comprised of a metal alloy matrix and particles of ceramic, cermet, tungsten carbide, silicon carbide, or boron carbide.

29. The method of claim 28 wherein the particles are tungsten carbide.