Methods and systems for remediating filtercake impairment around a subsea injection well

Abstract

Methods and systems for remediating filtercake buildup in a subsea injection well are provided herein. An exemplary method includes injecting a chemical solution into a riser tie-in connection using a chemical injection pump downstream of a water injection pump of an offshore production facility. The exemplary method also includes pumping, with the chemical injection pump, a portion of the chemical solution through a riser connected to the riser tie-in connection and to an injector region of an injection well connected to the riser. The injector region is in fluid communication with filtercake that is impairing the injector region. Further, the portion of the chemical solution is in contact with the filtercake. The exemplary method includes waiting at least a remediation time for the filtercake to be in contact with the chemical solution to cause remediation in the impairing of the injector region.

Description

METHODS AND SYSTEMS FOR REMEDIATING FILTERCAKE IMPAIRMENT AROUND A SUBSEA INJECTION WELL CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims priority to and the benefit of U.S. Provisional Application No. 63 / 602,719, entitled “METHODS AND SYSTEMS FOR REMEDIATING FILTERCAKE IMPAIRMENT AROUND A SUBSEA INJECTION WELL,” having a filing date of November 27, 2023, the disclosure of which is incorporated herein by reference in its entirety. FIELD OF THE INVENTION

[0002] The techniques described herein relate to the field of subsea production operations. More specifically, the techniques described herein relate to methods for increasing the performance of injector wells in a subsea production environment. BACKGROUND OF THE INVENTION

[0003] This section is intended to introduce various aspects of the art, which may be associated with embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

[0004] More than two-thirds of the earth is covered by oceans. As the petroleum industry continues its search for hydrocarbons, it is finding that more and more of the untapped hydrocarbon reservoirs are located beneath the oceans. Such reservoirs are referred to as “offshore reservoirs.”

[0005] A typical system used to produce hydrocarbons from offshore reservoirs uses hydrocarbon-producing wells located on the ocean floor. This type of production system, often referred to as a subsea production system (SPS), generally includes a subsea tree, manifolds, intervention systems, subsea processing systems, and the corresponding pipeline system. The SPS is placed on the ocean floor to direct the flow of production fluids from the producing wells, often referred to as “producers” or “subsea production wells,” towards the flowlines, to isolate the flow from the wells, and to allow access to perform workovers and interventions. Moreover, the produced hydrocarbons are transported to a host production facility.

[0006] The drilling and maintenance of remote offshore wells is expensive. In an effort to reduce drilling and maintenance expenses, remote offshore wells are often drilled in clusters. A grouping of wells in a clustered subsea arrangement is sometimes referred to as a “subsea wellsite.”A subsea wellsite typically includes producing wells completed for production at one or more “pay zones.”

[0007] The grouping of remote subsea wells facilitates the gathering of production fluids into a local production manifold. Fluids from clustered wells are delivered to the manifold through the jumpers. From the manifold, the production fluids may be delivered together to the host production facility through the flowlines and riser. For wellsites that are in deeper waters, the gathering and separating facility is typically a floating production, storage, and offloading vessel (FPSO).

[0008] One challenge facing offshore production operations is maintaining sufficient pressure in the subsea reservoir over time to ensure efficient production of hydrocarbons. Injection wells may be used to inject fluid into the subsea reservoir at strategic locations to increase formation pressure. Injection wells may be used to inject either water or gases into the subsurface formation in order to maintain sufficient pressure to produce hydrocarbons from the formation.

[0009] When drilling subsea wells, it is a typical practice to bring expensive equipment, such as a drilling rig, to the drilling site, then to remove that equipment once drilling is completed. Mud filtercake is deliberately created during drilling to prevent losses. It forms virtually instantaneously as the drill exposes fresh permeable rock. A filtercake can build up during injection, but this is composed of injected solids rather than mud.

[0010] When injection wells are first placed into operation, residual mud filtercake may block injectors from being able to provide fluid at sufficient volume. Water injector impairment caused by the filtercake buildup can place limits on the ability to provide long-term pressure support for producing wells.

[0011] An FPSO in a deepwater operation may support producing wells, water injection wells, gas injection wells, and / or water-alternating-gas (WAG) injection wells. When an injection well is drilled and completed with an oil-based mud, an open hole sweep containing a cleaning additive compromised of solvents, surfactants and water wetting agents is circulated to displace the mud and leave things in a water wet state. The efficacy of this treatment is typically not known until the injection well comes online. When the injection well is brought online, pressure transient analysis (PTA) and modeling assessments can ascertain how much of the wellbore is contributing to the overall injectivity. If the analysis shows that the cleanup up was ineffective, it may indicate that a mud filtercake was left in place during lower completion operations causing injector impairment.

[0012] One way to remediate an injection well is through subsea well intervention. Such subsea well intervention requires again bringing expensive equipment that is adapted to perform theintervention to the SPS. Examples of such equipment include a light well intervention vessel (LWIV) or a drilling rig. Additional cleanup additives may be pumped to change the wettability of the mud filtercake followed by acids and chelating agents to dissolve or disaggregate barite in the filtercake and restore injectivity. The cost of these jobs may be prohibitive though given the challenges around planning (for field wide usage), mobilization, and execution especially at the infancy of the life of a field.

[0013] Further, subsea well intervention using acid and chelating agents has often not proved to be highly effective and the efficacy of the treatment is not readily detectable prior to removal of the equipment needed to perform the intervention. Accordingly, known filtercake remediation methods are often not highly effective. An improved method of removing or remediating residual filtercake around injectors in subsea wells is desirable. SUMMARY OF THE INVENTION

[0014] An embodiment provided herein relates to a method for remediating filtercake buildup in a subsea injection well. The method includes injecting a chemical solution into a riser tie-in connection using a chemical injection pump downstream of a water injection pump of an offshore production facility. The method also includes pumping, with the chemical injection pump, at least a portion of the chemical solution through a riser connected to the riser tie-in connection and to an injector region of an injection well connected to the riser. The injector region is in fluid communication with filtercake that is impairing the injector region, so that at least a portion of the chemical solution makes contact with the filtercake. The method further includes waiting at least a remediation time for the filtercake to be in contact with the chemical solution to cause remediation in the impairing of the injector region.

[0015] Another embodiment provided herein relates to an injection well system. The injection well system includes an injector well that has an injector region that is impaired with filtercake. The injection well system also includes a chemical injection pump downstream of a water injection pump of an offshore production facility. The chemical injection pump is connected to a riser via a riser tie- in connection. The riser is in fluid communication with the injector region. The riser receives a chemical solution pumped from the chemical injection pump so that a portion of the chemical solution makes contact with the filtercake. Further, at least a portion of the chemical solution is left in contact with the filtercake for at least a remediation time to cause remediation in the filtercake impairing of the injector region.

[0016] A further embodiment provided herein relates to a well system. The well system includes an injector well that has an injector region that is impaired with filtercake. The well system also includes a chemical injection pump downstream of a water injection pump of an offshore production facility. The chemical injection pump is connected to a riser via a riser tie-in connection. The riser is in fluid communication with the injector region. The riser receives a chemical solution pumped from the chemical injection pump so that a portion of the chemical solution makes contact with the filtercake. A portion of the chemical solution is left in contact with the filtercake for at least a remediation time to cause remediation in the filtercake impairing of the injector region. The well system further includes a computing system that calculates an aspect of the chemical solution to provide an input to remediating the filtercake.

[0017] These and other features and attributes of the disclosed embodiments of the present techniques and their advantageous applications and / or uses will be apparent from the detailed description that follows. BRIEF DESCRIPTION OF THE DRAWINGS

[0018] To assist those of ordinary skill in the relevant art in making and using the subject matter described herein, reference is made to the appended drawings, where:

[0019] FIG.1 is a schematic view of an exemplary subsea production system including subsea production equipment;

[0020] FIG.2 is a schematic view of an exemplary injector well that may be remediated according to the present techniques;

[0021] FIG.3 is a schematic view of an injector region of an injector well that illustrates filtercake plugging as described herein;

[0022] FIG.4 is a diagram showing infrastructure of an offshore production facility, including a riser tie-in connection for injecting a low concentration chemical solution for remediation of filtercake according to the present techniques;

[0023] FIG.5 is a process flow diagram of an exemplary method for remediating filtercake in a subsea injection well according to the present techniques;

[0024] FIG.6 is a block diagram of an exemplary cluster computing system that may be utilized to implement at least a portion of the present techniques; and

[0025] FIG.7 is a block diagram of an exemplary non-transitory, computer-readable storage medium that may be used for the storage of data and modules of program instructions for implementing at least a portion of the present techniques.

[0026] It should be noted that the figures are merely examples of the present techniques and are not intended to impose limitations on the scope of the present techniques. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the techniques. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0027] In the following detailed description section, the specific examples of the present techniques are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for exemplary purposes only and simply provides a description of the embodiments. Accordingly, the techniques are not limited to the specific embodiments described below, but rather, include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims. Terminology

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

[0029] As used herein, the singular forms “a,” “an,” and “the” mean one or more when applied to any embodiment described herein. The use of “a,” “an,” and / or “the” does not limit the meaning to a single feature unless such a limit is specifically stated.

[0030] The terms “about” and “around” mean a relative amount of a material or characteristic that is sufficient to provide the intended effect. The exact degree of deviation allowable in some cases may depend on the specific context, e.g., ±1%, ±5%, ±10%, ±15%, etc. It should be understood by those of skill in the art that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numerical ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described are considered to be within the scope of the disclosure.

[0031] The term “and / or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and / or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and / or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and / or B,” when used in conjunction with open-ended language such as “including,” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.

[0032] As used herein, the term “any” means one, some, or all of a specified entity or group of entities, indiscriminately of the quantity.

[0033] The phrase “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 entities 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 or B” (or, equivalently, “at least one of A and B,” or, equivalently, “at least one of A and / or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, 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.

[0034] As used herein, the phrase “based on” does not mean “based only on,” unless expressly specified otherwise. In other words, the phrase “based on” means “based only on,” “based at least on,” and / or “based at least in part on.”

[0035] As used herein, the terms “example,” exemplary,” and “embodiment,” when used with reference to one or more components, features, structures, or methods according to the present techniques, are intended to convey that the described component, feature, structure, or method is an illustrative, non-exclusive example of components, features, structures, or methods according to the present techniques. Thus, the described component, feature, structure, or method is not intended to be limiting, required, or exclusive / exhaustive; and other components, features, structures, or methods, including structurally and / or functionally similar and / or equivalent components, features, structures, or methods, are also within the scope of the present techniques.

[0036] As used herein, the term “fluid” refers to gases and liquids, as well as to combinations of gases and liquids, combinations of gases and solids, combinations of liquids and solids, and combinations of gases, liquids, and solids.

[0037] A “hydrocarbon” is an organic compound that primarily includes the elements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. As used herein, the term “hydrocarbon” generally refers to components found in raw natural gas and oil.

[0038] The term “manifold” refers to an item of subsea production equipment that gathers production fluids from one or more subsea trees and delivers those fluids to a production line, either directly or through a jumper line.

[0039] As used herein, the term “production fluids” refers to fluids removed from a subsurface formation, including hydrocarbon fluids removed from an offshore reservoir.

[0040] The term “production facility” refers to any facility for receiving production fluids. The production facility may be a ship-shaped vessel located over a subsea wellsite, a floating production, storage, and offloading vessel (FPSO) located over or near a subsea wellsite, a near-shore separation facility, or an onshore separation facility.

[0041] As used herein, the term “resiliency” refers to the extent to which a particle is capable of volumetrically contracting in response to pressure increases and then subsequently recovering the lost volume in response to pressure decreases.

[0042] The term “subsea production system (SPS)” refers to an assembly of production equipment placed in a marine body. The marine body may be an ocean or a deep, freshwater lake,for example. Similarly, the term “subsea” encompasses both an ocean body and a deep, freshwater lake.

[0043] The term “subsea production equipment” refers to any item of equipment placed proximate the bottom of a marine body, such as an ocean floor, as part of an SPS.

[0044] The term “subsea well” refers to a well that has a tree proximate the bottom of a marine body, such as an ocean floor. Similarly, the term “subsea tree” refers to any collection of valves disposed over a wellhead in a marine body.

[0045] The term “substantially,” when used in reference to a quantity or amount of a material, or a specific characteristic thereof, 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 depend, in some cases, on the specific context.

[0046] The terms “riser” and “production riser” refer to any tubular structure or collection of lines for transporting production fluids to a production facility, such as an FPSO.

[0047] The term “umbilical” refers to any line that contains a collection of smaller lines. An umbilical may also be referred to as an “umbilical line” or an “umbilical cable.”

[0048] Certain embodiments and features are described herein using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges from any lower limit to any upper limit are contemplated unless otherwise indicated. All numerical values are “about” or “approximately” the indicated value, and account for experimental errors and variations that would be expected by those skilled in the art.

[0049] Furthermore, concentrations, dimensions, amounts, and / or other numerical data that are presented in a range format are to be interpreted flexibly to include not only the numerical values explicitly recited as the limits of the range, but also all individual numerical values or sub-ranges encompassed within that range, as if each numerical value and sub-range were explicitly recited. For example, a disclosed numerical range of 1 to 200 should be interpreted to include, not only the explicitly-recited limits of 1 and 200, but also individual values, such as 2, 3, 4, 197, 198, 199, etc., as well as sub-ranges, such as 10 to 50, 20 to 100, etc. Overview

[0050] As described above, filtercake hampers efficient operation of subsea injector wells during offshore production operations. However, to-date, suitable solutions to this issue are still lacking. The present techniques provide a remediation method that can be used in a deepwater environment when an FPSO is on location. Moreover, the present techniques may be performed with equipmenton the FPSO, rather than requiring the relocation of expensive resources to the site of the injection well to be remediated.

[0051] The present techniques target filtercake impairment resulting from filtercake left in place during lower completion operations due to ineffective drill-in fluid cleanup practices. Such filtercake impairment may prevent the full wellbore from contributing to the overall injectivity. Exemplary Subsea Production System and Corresponding Subsea Production Equipment

[0052] The producing wells are in fluid communication with the host production facility via a system of pipes that transport the hydrocarbons from the subsea wells on the ocean floor to the host production facility. This system of pipes typically includes a collection of jumpers, flowlines, and risers (among other subsea production equipment). Jumpers include pipes that lie on the ocean floor and are used to connect the individual wellheads to a central manifold. Flowlines also lie on the ocean floor and are used to transport production fluids from the manifold to the riser. The riser extends from the ocean floor, through the water column, and to the host production facility. In many instances, the top of the riser is supported by a floating buoy, which then connects to a flexible hose for delivering production fluids from the riser to the production facility.

[0053] FIG.1 is a schematic view of an exemplary subsea production system (SPS) 100 including subsea production equipment. The SPS 100 is configured to produce hydrocarbons from an offshore reservoir. The exemplary SPS 100 utilizes a single production line, including a production riser 102, although multiple production lines and / or risers could be used. Oil, gas, and, typically, water, which are generally referred to as “production fluids,” are produced through the riser 102. In some embodiments, the riser 102 is an 8-inch insulated production line. However, other sizes may be used.

[0054] The SPS 100 includes one or more subsea wells. For example, in the arrangement shown in FIG. 1, three subsea wells 104, 106, and 108 are included. In some embodiments, the subsea wells 104, 106, and 108 may include at least one production well and at least one injection well. However, in the arrangement shown in FIG. 1, at least one of the three subsea wells 104, 106, and 108 is an injection well, which may be remediated to reduce filtercake buildup as described herein.

[0055] Each subsea well 104, 106, and 108 includes a subsea tree 110 located on a marine floor 112, e.g., an ocean floor. Each subsea tree 110 delivers production fluids to a jumper 114. The jumpers 114 then deliver the production fluids to a manifold 116, which is configured to comingle the production fluids and export the production fluids from the wellsite through a subsea flowline 118 and the riser 102. Together, the flowline 118 and the riser 102 provide a single production line.

[0056] The riser 102 ties back to a production facility 120. The production facility 120, sometimes referred to as a “host facility” or a “gathering facility,” is any facility where production fluids are collected. The production facility may be, for example, a ship-shaped vessel capable of self-propulsion in a marine body 122, e.g., the ocean, having a marine surface 124 and the marine floor 112. The production facility may alternatively be fixed to land and reside near shore or immediately onshore. Another type of production facility is a tension leg platform (TLP).

[0057] In the exemplary embodiment described herein, the production facility 120 is a floating production, storage, and offloading vessel (FPSO) moored in the marine body 122. As explained herein, the production facility 120 is used to provide remediation of filtercake buildup.

[0058] As shown in FIG.1, the SPS 100 may include a production sled 126 for connecting the flowline 118 to the riser 102. In addition, the SPS 100 includes a utility umbilical 128, which is an integrated electrical / hydraulic control line. In particular, the utility umbilical 128 typically includes conductive wires for providing power to subsea production equipment. A control line within the utility umbilical 128 may carry hydraulic fluid used for controlling items of subsea production equipment, such as a subsea distribution unit (SDU) 130, the manifold 116, and the subsea trees 110 connected to the subsea wells 104, 106, and 108. Such control lines allow for the actuation of closure mechanisms and other subsea components from the surface.

[0059] The schematic view of FIG. 1 is not intended to indicate that the SPS 100 is to include all of the components shown in FIG. 1, or that the SPS 100 is limited to only the components shown in FIG.1. Rather, any number of components may be omitted from the SPS 100 or added to the SPS 100, depending on the details of the specific implementation.

[0060] FIG.2 is a schematic view of an exemplary injector well that may be remediated for filtercake buildup according to the present techniques. FIG.2 shows an injection well 200 that may be used to inject fluids such as water into a subsea reservoir 210 to maintain pressure in the subsea reservoir 210. Operation of the injection well 200 may be controlled by a control unit 202.

[0061] The injection well 200 includes a wellbore 204, which is drilled beneath the ocean floor 112 (FIG.1) into the subsea reservoir 210. A casing string 206 extends through the wellbore 204. Production tubing 208 extends through the casing string 206. One or more pumps in the production facility 120 may be used to pump injection fluids 214 such as water through an injector region 212 and into the subsea reservoir 210.

[0062] FIG.3 is a schematic view of the injector region 212 of the injection well 200. FIG. 3 illustrates filtercake plugging as described herein. As shown in FIG. 3, the injector region 212 isplugged with filtercake 300, impeding or preventing the injector region 212 from being able to efficiently deliver injection fluids 214 into the subsea reservoir 210.

[0063] The filtercake 300 is typically deposited during the drilling of the injection well 200. Moreover, the filtercake 300 results from the initial drilling of the injection well 200 and is not cleaned up effectively when drilling is completed.

[0064] The production facility 120 is equipped with chemical injection systems that could be used to deliver biocides, scale inhibitors, corrosion inhibitors, oxygen scavengers, etc. These chemicals could be introduced upstream of the water injection pumps of the production facility 120 and delivered downhole to the injector region 212 (FIG. 2) have a concentration of about 100 parts per million (ppm). Other exemplary concentrations may be used, including concentrations of about 50 ppm, about 250 ppm, about 500 ppm, about 750 ppm, about 1,000 ppm, about 2,500 ppm, about 5,000 ppm, about 7,500 ppm or about 10,000 ppm to name a few non-limiting examples. Remediation of the filtercake 300 using chemicals upstream of the water injection pumps may, however, be undesirable for a number of reasons. In particular, for remediation of a mud filtercake, concentrations greater than 10,000 ppm (equivalent to a concentration of about 1%) could be needed.

[0065] The chemicals used according to the techniques described herein are less aggressive as compared to acids and chelating agents that cannot be pumped directly from the FPSO. Those types of chemicals may have adverse side effects to the riser, flowlines, jumpers, manifolds, seals, tubing, etc. When an acid is pumped to remediate a well, a drilling rig or a LWIV should be deployed to the site and latched up directly to the wellhead. The treatment according to the present techniques avoids this effort and expense.

[0066] Even if the water injection pumps of the production facility 120 could deliver the concentration requirements, there may be overboard limitations to the amount of chemical that may be discharged if the well being treated is choked back. For example, discharging undiluted chemicals would need to be managed. In addition, there could be chemical compatibility considerations when injecting chemicals using the water injection pumps of the production facility 120. The pumps may not be rated to take certain chemicals at higher concentrations due to elastomer seal components that may exist inside of the pump. The elastomers may not be compatible with the chemical in the ranges required.

[0067] The present techniques exploit the notion that low concentration, less aggressive chemicals may be used to remediate the presence of the mud filtercake 300 using the existing infrastructure of the production facility 120. Moreover, the present techniques may be performedusing the production facility 120 without the need to move costly equipment such as a drilling rig or LWIV to the location of the injection well 200 to pump stronger chemicals to remediate the mud filtercake 300.

[0068] FIG.4 is a diagram showing infrastructure 400 of an offshore production facility, including a riser tie-in connection for injecting a low concentration chemical for remediation of filtercake 300 according to the present techniques. As used herein, the term “low concentration” means a concentration in the range of 0.5% to 5%. Specific examples of low concentrations include approximately 0.5%, 1.0%, 1.5%, 2.0%, 2.5%, 3.0%, 3.5%, 4.0%, 4.5% and 5.0%, to name just a few examples. Further, examples of chemicals that may be used for filtercake remediation include surfactants, such as water soluble ethoxylated alcohols balanced with oil soluble components, such as calcium or amine salts of dodecylbenzene sulfonates and wetting agents such as dioctyl sulfo succinate.

[0069] As shown in FIG.4, the production facility 120 includes a water injection pump 402 for pumping water to the injection well 200 as described herein. A riser tie-in connection 404 is provided on the downstream side of the water injection pump 402. The riser tie-in connection 404 is an input port that may receive fluids to be pumped into the riser 102 by a chemical injection pump 406. The chemical injection pump 406 is typically smaller in capacity and pressure than the water injection pump 402 with the ability to deliver a low concentration chemical solution at riser pressure to remediate the filtercake 300 from the injector region 212 (FIG.2) of the injection well 200 as described herein.

[0070] Because the chemical solution is being injected downstream of the main water injection pump(s) 402, the chemical injection pump 406 should match the pressure of those water injection pumps otherwise it may not be possible to inject anything into the riser tie-in connection 404. The practitioner will appreciate that water is still being injected while the chemical solution is introduced into the tie-in connection 404.

[0071] According to the present techniques, the filtercake 300 may be removed from the injector region 212 by injecting a low concentration chemical solution into the riser 102 (FIG.1) via the riser tie-in connection 404. The low concentration chemical solution may be pumped down through the riser 102, flowline, tubing and lower completion until it comes in contact with the mud filtercake 300 impairing the injector region 212. The injection well 200 should then be shut-in allowing the low concentration chemical solution to break down the mud filtercake 300 before being brought back online.

[0072] In an exemplary embodiment of the present techniques, the composition of the chemical solution is designed to change the wettability of the filtercake 300 to assist in breaking down the filtercake 300. By way of example, if the filtercake 300 is an emulsion, the composition of the chemical solution may be designed to break down the integrity of the emulsion.

[0073] In one example, a low concentration chemical solution is pumped into the riser tie-in connection 404 at some percentage of the water injection rate until a pill of some specific calculated volume is formed in the riser 102 and flowline. The low concentration of the chemical solution could be in a range described previously herein. The volume of the pill could be approximately 1,000 barrels in one non-limiting example. Other non-limiting examples of pill size include approximately 500 barrels, approximately 2,000 barrels, approximately 3,000 barrels, approximately 4,000 barrels, approximately 5,000 barrels, approximately 6,000 barrels, approximately 7,000 barrels, approximately 8,000 barrels, approximately 9,000 barrels, or approximately 10,000 barrels, to name just a few examples.

[0074] The pill may have a length that is longer than or greater than the length of the injector region 212. This will allow treatment to take place multiple times as the pill is repeatedly moved into position along the injector region 212 multiple times to bring fresh chemical solution into contact with the filtercake 300. The fresh chemical solution is allowed to soak the filtercake 300 for at least the remediation time for each of the multiple times the pill is moved. The pill may be pumped iteratively in this manner until the entire length of the pill has been brought into contact with the filtercake 300.

[0075] When the target pill size is formed, chemical injection into the riser tie-in connection 404 ceases and the water injection rate is ramped up to deliver the chemical to the injector region 212 (FIG. 2). The water injection rate to deliver the pill could be performed by the water injection pump 402. The chemical injection pump 406 that goes into the riser tie-in connection 404 is no longer needed after all the chemical is pumped into the riser. At that point, the main water injection pump(s) 402 continue(s) to pump the pill through the riser 102, flowline, manifold, jumper, etc. until it reaches the lower completion.

[0076] Once a desired amount of pill volume reaches the injector region 212, water injection is shut-in, and the low concentration chemical soaks the filtercake 300 for a prescribed period of time. The period of time to soak the filtercake 300 in the low concentration chemical is referred to herein as the remediation time. The remediation time is the time period in which disaggregation of the filtercake 300 begins to take place. In one example, the remediation time is a time in the rangebetween 24 hours and 48 hours. In other examples, the remediation time could range between one day and three days, one day and four days, one day and five days, one day and six days, one day to seven days, or one day to 30 days, to name a few non-limiting examples.

[0077] Water injection into the subsea reservoir 210 may then resume at a specified ramp-up rate to introduce fresh low concentration chemical from the original pill to the filtercake 300. The injection well 200 should be shut-in once again and allowed to soak the filtercake 300 with the fresh low concentration chemical. This procedure could be repeated several times until the total pill of low concentration chemical has been injected into the injector region 212 to soak the filtercake 300. At that time, full scale injection of fluids into the subsea reservoir 210 may slowly be brought back online, and pressures may be monitored.

[0078] The practitioner will appreciate that the present techniques employ the chemical solution to change the wettability of the oil-based mud from “oil wet” to “water wet.” After some period of time, the wettability of the mud filtercake is changed to water wet, and with the expected relative permeability benefit, the residual mud may be injected away into the subsea reservoir. In one example, the present techniques may be used in treatment of a desulfated seawater injector drilled with barite-based oil-based mud. The treatment makes the barite water wet, allowing the water, undersaturated with barium sulfate (BaSO4), to dissolve the barite. The remaining barite may then dissolve over time in the desulfated treated seawater that is injected. Injectivity performance should improve and could be confirmed by performing a series of step rate tests and pressure transient analysis.

[0079] FIG.5 is a process flow diagram of an exemplary method 500 for remediating filtercake in a subsea injection well according to the present techniques. Calculations about various aspects of the method 500 may be executed, at least in part, by one or more computing systems including one or more processors, such as the cluster computing system described with respect to FIG. 6, or any suitable variation(s) thereof. In some embodiments, such computing system(s) (or a portion of such computing systems) may be located at a centralized facility or distributed across a number of locations.

[0080] The method 500 begins at block 502, at which a chemical solution is injected into the riser tie-in connection 404 using the chemical injection pump 406, which is downstream of the water injection pump 402 of an offshore production facility such as an FPSO. As explained herein, the present techniques exploit the fact that a low concentration of chemicals may be used to treat filtercake buildup using existing infrastructure of an FPSO without the need to bring in expensiveresources, such as an LWIV or a drilling rig.

[0081] At block 502, the method 500 continues with the pumping by the chemical injection pump 406 of at least a portion of the chemical solution through the riser 102 connected to the riser tie-in connection 404 and to the injector region 212 of the injection well 200 connected to the riser 102. Filtercake 300 that is impairing the injector region 212 is in fluid communication therewith, such that at least a portion of the chemical solution is in contact with the filtercake 300.

[0082] Once the chemical solution is in contact with the filtercake 300, at least a remediation time is allowed to pass for the chemical solution to begin to disaggregate the filtercake 300. By soaking the filtercake, the solids (barite) in the mud start to disaggregate. Wettability is changed and that allows the residual mud to be swept away and the remaining barite to dissolve over time. The remediation time is indicated at block 506. The practitioner may determine the specific length of the remediation time based on conditions in the field, such as the strength and composition of the chemical solution and the extent to which the filtercake 300 is impairing the injector region 212. As explained herein, additional chemical solution may be pumped into contact with the filtercake 300 in iterations and this process may continue until the filtercake 300 has been exposed to sufficient chemical solution to remediate the filtercake 300 from the injector region 212.

[0083] FIG.6 is a block diagram of an exemplary cluster computing system 600 that may be utilized to implement at least a portion of the present techniques. As noted, the cluster computing system 600 may be used to compute aspects of the present techniques such as strength and composition of the chemical solution, the size of a pill made up of the chemical solution to be employed, and the remediation time to wait once the chemical solution is brought into contact with the filtercake 300 impairing the injector region 212.

[0084] The exemplary cluster computing system 600 shown in FIG.6 has four computing units 602A, 602B, 602C, and 602D, each of which may perform calculations for a portion of the present techniques. However, one of ordinary skill in the art will recognize that the cluster computing system 600 is not limited to this configuration, as any number of computing configurations may be selected. For example, a smaller analysis may be run on a single computing unit, such as a workstation, while a large calculation may be run on a cluster computing system 600 having tens, hundreds, or even more computing units.

[0085] The cluster computing system 600 may be accessed from any number of client systems 604A and 604B over a network 606, for example, through a high-speed network interface 608. Thecomputing units 602A to 602D may also function as client systems, providing both local computing support and access to the wider cluster computing system 600.

[0086] The network 606 may include a local area network (LAN), a wide area network (WAN), the Internet, or any combinations thereof. Each client system 604A and 604B may include one or more non-transitory, computer-readable storage media for storing the operating code and program instructions that are used to implement at least a portion of the present techniques, as described further with respect to the non-transitory, computer-readable storage media of FIG.7. For example, each client system 604A and 604B may include a memory device 610A and 610B, which may include random access memory (RAM), read only memory (ROM), and the like. Each client system 604A and 604B may also include a storage device 612A and 612B, which may include any number of hard drives, optical drives, flash drives, or the like.

[0087] The high-speed network interface 608 may be coupled to one or more buses in the cluster computing system 600, such as a communications bus 614. The communication bus 614 may be used to communicate instructions and data from the high-speed network interface 608 to a cluster storage system 616 and to each of the computing units 602A to 602D in the cluster computing system 600. The communications bus 614 may also be used for communications among the computing units 602A to 602D and the cluster storage system 616. In addition to the communications bus 614, a high-speed bus 618 can be present to increase the communications rate between the computing units 602A to 602D and / or the cluster storage system 616.

[0088] In some embodiments, the one or more non-transitory, computer-readable storage media of the cluster storage system 616 include storage arrays 620A, 620B, 620C and 620D for the storage of models, data. visual representations, results (such as graphs, charts, and the like used to convey results obtained using the present techniques), code, and other information concerning the implementation of at least a portion of the present techniques. The storage arrays 620A to 620D may include any combinations of hard drives, optical drives, flash drives, or the like.

[0089] Each computing unit 602A to 602D includes at least one processor 622A, 622B, 622C and 622D and associated local non-transitory, computer-readable storage media, such as a memory device 624A, 624B, 624C and 624D and a storage device 626A, 626B, 626C and 626D, for example. Each processor 622A to 622D may be a multiple core unit, such as a multiple core central processing unit (CPU) or a graphics processing unit (GPU). Each memory device 624A to 624D may include ROM and / or RAM used to store program instructions for directing the corresponding processor 622A to 622D to implement at least a portion of the present techniques. Each storagedevice 626A to 626D may include one or more hard drives, optical drives, flash drives, or the like. In addition, each storage device 626A to 626D may be used to provide storage for models, intermediate results, data, images, or code used to implement at least a portion of the present techniques.

[0090] The present techniques are not limited to the architecture or unit configuration illustrated in FIG. 6. For example, any suitable processor-based device may be utilized for implementing at least a portion of the embodiments described herein, including (without limitation) personal computers, laptop computers, computer workstations, mobile devices, and multi-processor servers or workstations with (or without) shared memory. Moreover, the embodiments described herein may be implemented, at least in part, on application specific integrated circuits (ASICs) or very-large-scale integrated (VLSI) circuits. In fact, those skilled in the art may utilize any number of suitable structures capable of executing logical operations according to the embodiments described herein.

[0091] FIG.7 is a block diagram of an exemplary non-transitory, computer-readable storage medium 700 that may be used for the storage of data and modules of program instructions for implementing at least a portion of the present techniques. The non-transitory, computer-readable storage medium 700 may include a memory device, a hard disk, and / or any number of other devices, as described herein. A processor 702 may access the non-transitory, computer-readable storage medium 700 over a bus or network 704. While the non-transitory, computer-readable storage medium 700 may include any number of modules for implementing the present techniques, in some embodiments, the non-transitory, computer-readable storage medium 700 includes a filtercake remediation calculation module 706 for performing the techniques described herein (and / or any suitable variations thereof). Moreover, the filtercake remediation calculation module 706 may be adapted to analyze data to determine the composition and amount of low concentration chemical solution to be delivered to the injector region 212 of the injection well 200 in order to remediate filtercake buildup as described herein, or the remediation time to leave the chemical solution in contact with the filtercake 300. Embodiments of Present Techniques

[0092] In one or more embodiments, the present techniques may be susceptible to various modifications and alternative forms, such as the following embodiments as noted in paragraphs 1 to 55: 1. A method for remediating filtercake buildup in a subsea injection well, the method comprising: injecting a chemical solution into a riser tie-in connection using a chemical injection pump downstream of a water injection pump of an offshore production facility; pumping, with thechemical injection pump, at least a portion of the chemical solution through a riser connected to the riser tie-in connection and to an injector region of an injection well connected to the riser, the injector region being in fluid communication with filtercake that is impairing the injector region, so that at least a portion of the chemical solution makes contact with the filtercake; and waiting at least a remediation time for the filtercake to be in contact with the chemical solution to cause remediation in the impairing of the injector region. 2. The method recited in paragraph 1, wherein the chemical solution comprises a surfactant. 3. The method recited in paragraph 2, wherein the surfactant comprises a water soluble ethoxylated alcohol balanced with an oil soluble component. 4. The method recited in any of paragraph 3, wherein the oil soluble component includes a calcium salt or an amine salt of dodecylbenzene sulfonates. 5. The method recited in any of paragraphs 1 to 4, wherein the chemical solution comprises a wetting agent. 6. The method recited in any of paragraph 5, wherein the wetting agent comprises a dioctyl sulfo succinate. 7. The method recited in any of paragraphs 1 to 6, wherein the chemical solution is a low concentration chemical solution. 8. The method recited in any of paragraphs 1 to 7, wherein composition of the chemical solution is designed to change wettability of the filtercake. 9. The method recited in paragraph 8, wherein the filtercake is an emulsion and composition of the chemical solution is designed to break down integrity of the emulsion. 10. The method recited in any of paragraphs 1 to 9, wherein the chemical solution forms a pill of predetermined size in the riser. 11. The method recited in paragraph 10, wherein the pill has a length greater than the length of the injector region, and wherein the pill is pumped into contact with the injector region multiple times until the length of the pill has been brought into contact with the filtercake, waiting at least the remediation time between each of the multiple times. 12. The method recited in any of paragraphs 1 to 11, comprising shutting in the injection well during the remediation time. 13. The method recited in any of paragraphs 1 to 12, wherein the remediation time is determined based on sufficiency of the chemical solution to disaggregate at least a portion of the filtercake during the remediation time.14. The method recited in any of paragraphs 1 to 13, wherein the offshore production facility comprises a floating production, storage, and offloading vessel (FPSO). 15. The method recited in any of paragraphs 1 to 14, wherein the riser tie-in connection is located on the offshore production facility. 16. The method recited in any of paragraphs 1 to 15, comprising repeating the pumping at least a portion of the chemical solution and waiting for the remediation time. 17. The method recited in any of paragraphs 1 to 16, wherein the remediation time comprises a time in the range between 24 hours and 48 hours. 18. An injection well system, comprising: an injector well having an injector region that is impaired with filtercake; a chemical injection pump downstream of a water injection pump of an offshore production facility, the chemical injection pump connected to a riser via a riser tie-in connection, the riser being in fluid communication with the injector region; wherein the riser receives a chemical solution pumped from the chemical injection pump so that at least a portion of the chemical solution makes contact with the filtercake; and wherein at least a portion of the chemical solution is left in contact with the filtercake for at least a remediation time to cause remediation in the filtercake impairing of the injector region. 19. The well system recited in paragraph 18, wherein the chemical solution comprises a surfactant. 20. The well system recited in paragraphs 18 or 19, wherein the surfactant comprises a water soluble ethoxylated alcohol balanced with an oil soluble component. 21. The well system recited in any of paragraph 20, wherein the oil soluble component includes a calcium salt or an amine salt of dodecylbenzene sulfonates. 22. The well system recited in any of paragraphs 18 to 21, wherein the chemical solution comprises a wetting agent. 23. The well system recited in paragraph 22, wherein the wetting agent comprises a dioctyl sulfo succinate. 24. The well system recited in any of paragraphs 18 to 23, wherein the chemical solution is a low concentration chemical solution. 25. The well system recited in any of paragraphs 18 to 24, wherein composition of the chemical solution is designed to change wettability of the filtercake. 26. The well system recited in paragraph 25, wherein the filtercake is an emulsion and composition of the chemical solution is designed to break down integrity of the emulsion. 27. The well system recited in any of paragraphs 18 to 26, wherein the chemical solution forms a pillof predetermined size in the riser. 28. The well system recited in paragraph 27, wherein the pill has a length greater than the length of the injector region, and wherein the pill is pumped into contact with the injector region multiple times until the length of the pill has been brought into contact with the filtercake, waiting at least the remediation time between each of the multiple times. 29. The well system recited in any of paragraphs 18 to 28, wherein the injection well is shut in during the remediation time. 30. The well system recited in any of paragraphs 18 to 29, wherein the remediation time is determined based on sufficiency of the chemical solution to disaggregate at least a portion of the filtercake during the remediation time. 31. The well system recited in any of paragraphs 18 to 30, wherein the offshore production facility comprises a floating production, storage, and offloading vessel (FPSO). 32. The well system recited in any of paragraphs 18 to 31, wherein the riser tie-in connection is located on the offshore production facility. 33. The well system recited in any of paragraphs 18 to 32, wherein the pumping at least a portion of the chemical solution and waiting for at least the remediation time are repeated. 34. The well system recited in any of paragraphs 18 to 33, wherein the remediation time comprises a time in the range between 24 hours and 48 hours. 35. A well system, comprising: an injector well having an injector region that is impaired with filtercake; a chemical injection pump downstream of a water injection pump of an offshore production facility, the chemical injection pump connected to a riser via a riser tie-in connection, the riser being in fluid communication with the injector region; wherein the riser receives a chemical solution pumped from the chemical injection pump so that at least a portion of the chemical solution makes contact with the filtercake; wherein the at least a portion of the chemical solution is left in contact with the filtercake for at least a remediation time to cause remediation in the filtercake impairing of the injector region; and a computing system that calculates an aspect of the chemical solution to provide an input to remediating the filtercake. 36. The well system recited in paragraph 35, wherein the chemical solution comprises a surfactant. 37. The well system recited in paragraphs 35 or 36, wherein the surfactant comprises a water soluble ethoxylated alcohol balanced with an oil soluble component. 38. The well system recited in paragraph 37, wherein the oil soluble component includes a calcium salt or an amine salt of dodecylbenzene sulfonates.39. The well system recited in any of paragraphs 35 to 38, wherein the chemical solution comprises a wetting agent. 40. The well system recited in paragraph 39, wherein the wetting agent comprises a dioctyl sulfo succinate. 41. The well system recited in any of paragraphs 35 to 40, wherein the chemical solution is a low concentration chemical solution. 42. The well system recited in any of paragraphs 35 to 41, wherein composition of the chemical solution is designed to change wettability of the filtercake. 43. The well system recited in paragraph 42, wherein the filtercake is an emulsion and composition of the chemical solution is designed to break down integrity of the emulsion. 44. The well system recited in any of paragraphs 35 to 43, wherein the chemical solution forms a pill of predetermined size in the riser. 45. The well system recited in paragraph 44, wherein the pill has a length greater than the length of the injector region, and wherein the pill is pumped into contact with the injector region multiple times until the length of the pill has been brought into contact with the filtercake, waiting at least the remediation time between each of the multiple times. 46. The well system recited in any of paragraphs 35 to 45, wherein the injection well is shut in during the remediation time. 47. The well system recited in any of paragraphs 35 to 46, wherein the remediation time is determined based on sufficiency of the chemical solution to disaggregate at least a portion of the filtercake during the remediation time. 48. The well system recited in any of paragraphs 35 to 47, wherein the offshore production facility comprises a floating production, storage, and offloading vessel (FPSO). 49. The well system recited in any of paragraphs 35 to 48, wherein the riser tie-in connection is located on the offshore production facility. 50. The well system recited in any of paragraphs 35 to 49, wherein the pumping at least a portion of the chemical solution and waiting for the remediation time are repeated. 51. The well system recited in any of paragraphs 35 to 50, wherein the aspect of the chemical solution includes a composition of the chemical solution. 52. The well system recited in any of paragraphs 35 to 51, wherein the aspect of the chemical solution includes a concentration of the chemical solution. 53. The well system recited in any of paragraphs 35 to 52, wherein the computing system calculatesthe remediation time. 54. The well system recited in any of paragraphs 35 to 53, wherein the computing system calculates a size of a pill to include the chemical solution. 55. The well system recited in any of paragraphs 35 to 54, wherein the remediation time comprises a time in the range between 24 hours and 48 hours.

[0093] While the embodiments described herein are well-calculated to achieve the advantages set forth, it will be appreciated that such embodiments are susceptible to modification, variation, and change without departing from the spirit thereof. In other words, the particular embodiments described herein are illustrative only, as the teachings of the present techniques may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended on the details of formulation, construction, or design herein shown, other than as described in the claims below. Moreover, the systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and / or any optional element disclosed herein. While compositions and methods are described in terms of “comprising” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Indeed, the present techniques include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

Claims

CLAIMS What is claimed is:

1. A method for remediating filtercake buildup in a subsea injection well, the method comprising: injecting a chemical solution into a riser tie-in connection using a chemical injection pump downstream of a water injection pump of an offshore production facility; pumping, with the chemical injection pump, at least a portion of the chemical solution through a riser connected to the riser tie-in connection and to an injector region of an injection well connected to the riser, the injector region being in fluid communication with filtercake that is impairing the injector region, so that at least a portion of the chemical solution makes contact with the filtercake; and waiting at least a remediation time for the filtercake to be in contact with the chemical solution to cause remediation in the impairing of the injector region.

2. The method recited in claim 1, wherein the chemical solution comprises a surfactant.

3. The method recited in claim 2, wherein the surfactant comprises a water soluble ethoxylated alcohol balanced with an oil soluble component.

4. The method recited in claim 3, wherein the oil soluble component includes a calcium salt or an amine salt of dodecylbenzene sulfonates.

5. The method recited in claim 1, wherein the chemical solution comprises a wetting agent.

6. The method recited in claim 5, wherein the wetting agent comprises a dioctyl sulfo succinate.

7. The method recited in claim 1, wherein the chemical solution is a low concentration chemical solution.

8. The method recited in claim 1, wherein composition of the chemical solution is designed to change wettability of the filtercake.

9. The method recited in claim 8, wherein the filtercake is an emulsion and composition of the chemical solution is designed to break down integrity of the emulsion.

10. The method recited in claim 1, wherein the chemical solution forms a pill of predetermined size in the riser.

11. The method recited in claim 10, wherein the pill has a length greater than the length of the injector region, and wherein the pill is pumped into contact with the injector region multiple times until the length of the pill has been brought into contact with the filtercake, waiting at least the remediation time between each of the multiple times.

12. The method recited in claim 1, comprising shutting in the injection well during the remediation time.

13. The method recited in claim 1, wherein the remediation time is determined based on sufficiency of the chemical solution to disaggregate at least a portion of the filtercake during the remediation time.

14. The method recited in claim 1, wherein the offshore production facility comprises a floating production, storage, and offloading vessel (FPSO).

15. The method recited in claim 1, wherein the riser tie-in connection is located on the offshore production facility.

16. The method recited in claim 1, comprising repeating the pumping at least a portion of the chemical solution and waiting for the remediation time.

17. The method recited in claim 1, wherein the remediation time comprises a time in the range between 24 hours and 48 hours.

18. An injection well system, comprising: an injector well having an injector region that is impaired with filtercake;a chemical injection pump downstream of a water injection pump of an offshore production facility, the chemical injection pump connected to a riser via a riser tie-in connection, the riser being in fluid communication with the injector region; wherein the riser receives a chemical solution pumped from the chemical injection pump so that at least a portion of the chemical solution makes contact with the filtercake; and wherein at least a portion of the chemical solution is left in contact with the filtercake for at least a remediation time to cause remediation in the filtercake impairing of the injector region.

19. The well system recited in claim 18, wherein the chemical solution comprises a surfactant.

20. The well system recited in claim 19, wherein the surfactant comprises a water soluble ethoxylated alcohol balanced with an oil soluble component.

21. The well system recited in claim 20, wherein the oil soluble component includes a calcium salt or an amine salt of dodecylbenzene sulfonates.

22. The well system recited in claim 18, wherein the chemical solution comprises a wetting agent.

23. The well system recited in claim 22, wherein the wetting agent comprises a dioctyl sulfo succinate.

24. The well system recited in claim 18, wherein the chemical solution is a low concentration chemical solution.

25. The well system recited in claim 18, wherein composition of the chemical solution is designed to change wettability of the filtercake.

26. The well system recited in claim 25, wherein the filtercake is an emulsion and composition of the chemical solution is designed to break down integrity of the emulsion.

27. The well system recited in claim 18, wherein the chemical solution forms a pill ofpredetermined size in the riser.

28. The well system recited in claim 27, wherein the pill has a length that is longer than the injector region, and wherein the pill is pumped into contact with the injector region multiple times until the length of the pill has been brought into contact with the filtercake, waiting at least the remediation time between each of the multiple times.

29. The well system recited in claim 18, wherein the injection well is shut in during the remediation time.

30. The well system recited in claim 18, wherein the remediation time is determined based on sufficiency of the chemical solution to disaggregate at least a portion of the filtercake during the remediation time.

31. The well system recited in claim 18, wherein the offshore production facility comprises a floating production, storage, and offloading vessel (FPSO).

32. The well system recited in claim 18, wherein the riser tie-in connection is located on the offshore production facility.

33. The well system recited in claim 18, wherein the pumping at least a portion of the chemical solution and waiting for at least the remediation time are repeated.

34. The well system recited in claim 18, wherein the remediation time comprises a time in the range of 24 hours to 48 hours.

35. A well system, comprising: an injector well having an injector region that is impaired with filtercake; a chemical injection pump downstream of a water injection pump of an offshore production facility, the chemical injection pump connected to a riser via a riser tie-in connection, the riser being in fluid communication with the injector region; wherein the riser receives a chemical solution pumped from the chemical injection pump sothat at least a portion of the chemical solution makes contact with the filtercake; wherein the at least a portion of the chemical solution is left in contact with the filtercake for at least a remediation time to cause remediation in the filtercake impairing of the injector region; and a computing system that calculates an aspect of the chemical solution to provide an input to remediating the filtercake.

36. The well system recited in claim 35, wherein the chemical solution comprises a surfactant.

37. The well system recited in claim 35, wherein the surfactant comprises a water soluble ethoxylated alcohol balanced with an oil soluble component.

38. The well system recited in claim 37, wherein the oil soluble component includes a calcium salt or an amine salt of dodecylbenzene sulfonates.

39. The well system recited in claim 35, wherein the chemical solution comprises a wetting agent.

40. The well system recited in claim 39, wherein the wetting agent comprises a dioctyl sulfo succinate.

41. The well system recited in claim 35, wherein the chemical solution is a low concentration chemical solution.

42. The well system recited in claim 35, wherein composition of the chemical solution is designed to change wettability of the filtercake.

43. The well system recited in claim 42, wherein the filtercake is an emulsion and composition of the chemical solution is designed to break down integrity of the emulsion.

44. The well system recited in claim 35, wherein the chemical solution forms a pill of predetermined size in the riser.

45. The well system recited in claim 44, wherein the pill has a length that is longer than the injector region, and wherein the pill is pumped into contact with the injector region multiple times until the length of the pill has been brought into contact with the filtercake, waiting at least the remediation time between each of the multiple times.

46. The well system recited in claim 35, wherein the injection well is shut in during the remediation time.

47. The well system recited in claim 35, wherein the remediation time is determined based on sufficiency of the chemical solution to disaggregate at least a portion of the filtercake during the remediation time.

48. The well system recited in claim 35, wherein the offshore production facility comprises a floating production, storage, and offloading vessel (FPSO).

49. The well system recited in claim 35, wherein the riser tie-in connection is located on the offshore production facility.

50. The well system recited in claim 35, wherein the pumping at least a portion of the chemical solution and waiting for the remediation time are repeated.

51. The well system recited in claim 35, wherein the aspect of the chemical solution includes a composition of the chemical solution.

52. The well system recited in claim 35, wherein the aspect of the chemical solution includes a concentration of the chemical solution.

53. The well system recited in claim 35, wherein the computing system calculates the remediation time.

54. The well system recited in claim 35, wherein the computing system calculates a size of a pill to include the chemical solution.

55. The well system recited in claim 35, wherein the remediation time comprises a time in the range between 24 hours and 48 hours.

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