Method For Managing Hydrates In Subsea Production Line

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the present invention generally relate to the field of subsea production operations. Embodiments of the present invention further pertain to methods for managing hydrate formation in subsea production equipment such as a flowline.

2. Background of the Invention

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.

A typical system used to produce hydrocarbons from offshore reservoirs uses hydrocarbon-producing wells located on the ocean floor. The producing wells are referred to as “producers” or “subsea production wells.” The produced hydrocarbons are transported to a host production facility. The production facility is located on the surface of the ocean or immediately on-shore.

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 comprises a collection of jumpers, flowlines and risers. Jumpers are typically referred to in the industry as the portion of pipes that lie on the floor of the body of water. They connect the individual wellheads to a central manifold. The flowline also lies on the marine floor, and transports production fluids from the manifold to a riser. The riser refers to the portion of a production line that extends from the seabed, 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.

The drilling and maintenance of remote offshore wells is expensive. In an effort to reduce drilling and maintenance expenses, remote offshore wells are oftentimes drilled in clusters. A grouping of wells in a clustered subsea arrangement is sometimes referred to as a “subsea well-site.” A subsea well-site typically includes producing wells completed for production at one and oftentimes more “pay zones.” In addition, a well-site will oftentimes include one or more injection wells to aid in maintaining in-situ pressure for water drive and gas expansion drive reservoirs.

The grouping of remote subsea wells facilitates the gathering of production fluids into a local production manifold. Fluids from the clustered wells are delivered to the manifold through the jumpers. From the manifold, production fluids may be delivered together to the host production facility through the flowline and the riser. For well-sites that are in deeper waters, the gathering facility is typically a floating production storage and offloading vessel, or “FPSO.” The FPSO serves as a gathering and separating facility.

One challenge facing offshore production operations is flow assurance. During production, the produced fluids will typically comprise a mixture of crude oil, water, light hydrocarbon gases (such as methane), and other gases such as hydrogen sulfide and carbon dioxide. In some instances, solid materials such as sand may be mixed with the fluids. The solid materials entrained in the produced fluids may typically be deposited during “shut-ins,” i.e. production stoppages, and require removal.

Of equal concern, changes in temperature, pressure and/or chemical composition along the pipes may cause the deposition of other materials such as methane hydrates, waxes or scales on the internal surface of the flowlines and risers. These deposits need to be periodically removed, as build-up of these materials can reduce line size and constrict flow.

Hydrates are crystals formed by water in contact with natural gases and associated liquids, in a ratio of 85 mole % water to 15% hydrocarbons. Hydrates can form when hydrocarbons and water are present at the right temperature and pressure, such as in wells, flow lines, or valves. The hydrocarbons become encaged in ice-like solids which do not flow, but which rapidly grow and agglomerate to sizes which can block flow lines. Hydrate formation most typically occurs in subsea production lines which are at relatively low temperatures and elevated pressures.

The low temperatures and high pressures of a deepwater environment cause hydrate formation as a function of gas-to-water composition. In a subsea pipeline, hydrate masses usually form at the hydrocarbon-water interface, and accumulate as flow pushes them downstream. The resulting porous hydrate plugs have the unusual ability to transmit some degree of gas pressure, while acting as a flow hindrance to liquid. Both gas and liquid may sometimes be transmitted through the plug; however, lower viscosity and surface tension favors the flow of gas.

It is desirable to maintain flow assurance between cleanings by minimizing hydrate formation. One offshore tool used for hydrate plug removal is the depressurization of the pipeline system. Traditionally, depressurization is most effective in the presence of lower water cuts. However, the depressurization process sometimes prevents normal production for several weeks. At higher water cuts, gas lift procedures may be required. Further, hydrates may quickly re-form when the well is placed back on line.

Most known deepwater subsea pipeline arrangements rely on two production lines for hydrate management. In the event of an unplanned shutdown, production fluid in the production flowline and riser is displaced with dehydrated dead crude oil using a pig. Displacement is completed before the production fluids (which are typically untreated or “uninhibited”) cool down below the hydrate formation temperature. This prevents the creation of a hydrate blockage in the production lines. The pig is launched into one production line, is driven with the dehydrated dead crude out to the production manifold, and is forced back to the host facility through the second production line.

The two-production-line operation is feasible for large installations. However, for relatively small developments the cost of a second production line can be prohibitive.

It is also known to use methanol or other suitable hydrate inhibitor in connection with a hydrate management operation. In this respect, a large quantity of methanol may be pumped into the production line ahead of the displacement fluid and the pig. Displacing methanol out of the service line and into the production line ahead of the displacement fluid helps to ensure that any uninhibited production fluid in the production line that is not displaced out of the line will be inhibited by methanol. However, this procedure generally requires that large quantities of methanol be stored on the production facility. An improved process of hydrate management is needed.

Other relevant information may be found in: U.S. Pat. Nos. 6,152,993; 6,015,929; 6,025,302; 6,214,091; commonly assigned International Patent Application Publication No. WO 2006/031335 filed on Aug. 11, 2005; U.S. application Ser. No. 11/660,777; and U.S. Provisional Patent Application No. 60/995,161.

SUMMARY OF THE INVENTION

A method for managing hydrates in a subsea production system is provided. The system has a production facility, a control umbilical for delivering displacement fluids from the production facility, at least one subsea production well, and a single production line for delivering produced fluids to the production facility. The method includes producing hydrocarbon fluids from the at least one subsea production well and through the single production line, and then shutting in the flow of produced fluids from the subsea well and the production line. The method also includes depressurizing the production line to substantially reduce a solution gas concentration in the produced hydrocarbon fluids, and then repressurizing the production line to urge any gas remaining in a free-gas phase within the production line back into solution. The step of repressurizing the production line preferably is accomplished by pumping the displacement fluid into the control umbilical and into the production line. In addition, the method includes displacing production fluids within the production line. This may be done by moving the displacement fluids from a service line within the umbilical line, and into the production line.

The displacement fluids preferably comprise a hydrocarbon-based fluid having a low dosage hydrate inhibitor (LDHI). In one aspect, the displacement fluid is substantially without light hydrocarbon gases. Preferably, the displacement fluid comprises dead crude, diesel, or combinations thereof, along with the LDHI inhibitor. Preferably, the displacement fluid is injected into a service line in the control umbilical.

The step of displacing production fluids may comprise injecting the displacement fluid into the service line at a maximum allowable rate for the service line. For example, the step of displacing production fluids may comprise injecting the displacement fluid into the service line at a rate of 5,000 to 9,000 bpd. In any respect, the step of displacing production fluids may be performed without the use of a pig ahead of the displacement fluid.

In one aspect, the LDHI is a kinetic hydrate inhibitor. Nonlimiting examples include polyvinylcaprolactam and polyisopropylmethacrylamide. In another aspect, the LDHI is an anti-agglomerant. Nonlimiting examples include tributylhexadecylphosphonium bromide, tributylhexadecylammonium bromide, and di-butyl di-dodecylammonium bromide.

The method may further include the step of monitoring the production fluids as they are displaced from the production line to evaluate water content and gas phase. Alternatively, or in addition, the method may include further displacing the production fluids from the production line to urge production fluids from the production line to the production facility until substantially all water content has been removed. Further still, the method may include further displacing the production fluids from the production line to urge substantially all of the production fluids from the production line to the production facility, leaving the production line full of displacement fluids and LDHI.

Certain of the steps may be repeated. For example, the method may further include repeating the depressurizing step, repeating the repressurizing step, and repeating the displacing step. Whether or not these steps are repeated, the method may further comprise producing hydrocarbon fluids after the displacement fluid has been pumped through the production line. The flow of produced fluids is thus re-initiated from the subsea well, through the single production line, and to the production facility. Thereafter, the produced fluids may be transported to shore.

It is understood that the production facility may be of any type. For example, the production facility may be a floating production, storage and offloading vessel (“FPSO”). Alternatively, the production facility may be a ship-shaped gathering vessel or a production facility that is near shore or onshore.

It is also understood that the subsea production system may include other components. For example, the subsea production system may have a manifold and an umbilical termination assembly. The manifold provides a subsea gathering point for production fluids, while the umbilical termination assembly provides a subsea connection for injection chemicals. The control umbilical may comprise a first umbilical portion that connects the production facility with the umbilical termination assembly, and a second umbilical portion that connects the umbilical termination assembly with the manifold.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the features of the present invention can be better understood, certain drawings, charts and diagrams are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications.

FIG. 1 is a perspective view of a subsea production system utilizing a single production line and a utility umbilical line. The system is in production.

FIG. 2 is a flowchart demonstrating steps for performing the hydrate management process of the present invention, in one embodiment.

FIG. 3 is a partial schematic view of the subsea production system of FIG. 1. A utility umbilical and a production line are seen.

FIG. 4 is another schematic view of the production system of FIG. 1. The utility umbilical and the production line are again seen. The valve connecting the utility umbilical with the production line has been opened so that production fluids may be displaced.

FIG. 5 is yet another schematic view of the production system of FIG. 1. The utility umbilical and the production line are again seen. The valve connecting the utility umbilical with the production line remains open. Production fluids have been substantially displaced.

FIG. 6 is a graph demonstrating water content in the production line during displacement, as a function of displacement rate.

FIG. 7 is a graph comparing aqueous phase content and gas phase content in the production line during displacement, as a function of time.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS
Definitions

As used herein, the term “displacement fluid” refers to a fluid used to displace another fluid. Preferably, the displacement fluid has no hydrocarbon gases. Non-limiting examples include dead crude and diesel.

The term “umbilical” refers to any line that contains a collection of smaller lines, including at least one service line for delivering a working fluid. The “umbilical” may also be referred to as an umbilical line or umbilical cable. The working fluid may be a chemical treatment such as a hydrate inhibitor or a displacement fluid. The umbilical will typically include additional lines, such as hydraulic power lines and electrical power cables.

The term “service line” refers to any tubing within an umbilical. The service line is sometimes referred to as an umbilical service line, or USL. One example of a service line is an injection tubing used to inject a chemical.

The term “low dosage hydrate inhibitor,” or “LDHI,” refers to both anti-agglomerants and kinetic hydrate inhibitors. It is intended to encompass any non-thermodynamic hydrate inhibitor.

The term “production facility” means any facility for receiving produced hydrocarbons. The production facility may be a ship-shaped vessel located over a subsea well site, an FPSO vessel (floating production, storage and offloading vessel) located over or near a subsea well site, a near-shore separation facility, or an onshore separation facility. Synonymous terms include “host production facility” or “gathering facility.”

The terms “tieback,” “tieback line,” and “riser” and “production line” are used interchangeably herein, and are intended to be synonymous. These terms mean any tubular structure or collection of lines for transporting produced hydrocarbons to a production facility. A production line may include, for example, a riser, flowlines, spools, and topside hoses.

The term “production line” means a riser and any other pipeline used to transport production fluids to a production facility. The production line may include, for example, a subsea production line and a flexible jumper.

“Subsea production system” means an assembly of production equipment placed in a marine body. The marine body may be an ocean environment, or it may be, for example, a fresh water lake. Similarly, “subsea” includes both an ocean body and a deepwater lake.

“Subsea equipment” means any item of equipment placed proximate the bottom of a marine body as part of a subsea production system.

“Subsea well” means a well that has a tree proximate the marine body bottom, such as an ocean bottom. “Subsea tree,” in turn, means any collection of valves disposed over a wellhead in a water body.

“Manifold” means any item of subsea equipment that gathers produced fluids from one or more subsea trees, and delivers those fluids to a production line, either directly or through a jumper line.

“Inhibited” means that produced fluids have been mixed with or otherwise been exposed to a chemical inhibitor for inhibiting formation of gas hydrates including natural gas hydrates. Conversely, “uninhibited” means that produced fluids have not been mixed with or otherwise been exposed to a chemical inhibitor for inhibiting formation of gas hydrates.

Description of Selected Specific Embodiments

FIG. 1 provides a perspective view of a subsea production system 10 which may be used to produce hydrocarbons from a subterranean offshore reservoir. The system 10 utilizes a single production line, including a riser 38. Oil, gas and, typically, water, referred to as production fluids, are produced through the production riser 38. In the illustrative system 10, the production riser 38 is an 8-inch insulated production line. However, other sizes may be used. Thermal insulation is provided for the production riser 38 to maintain warmer temperatures for the production fluids and to inhibit hydrate formation during production. Preferably, the production flowline protects against hydrate formation during a minimum of 20 hours of cool-down time during shut-in conditions.

The production system 10 includes one or more subsea wells. In this arrangement, three wells 12, 14 and 16 are shown. The wells 12, 14, 16 may include at least one injection well and at least one production well. In the illustrative system 10, wells 12, 14, 16 are all producers, thereby forming a production cluster.

Each of the wells 12, 14, 16 has a subsea tree 15 on a marine floor 85. The trees 15 deliver production fluids to a jumper 22, or short flowline. The jumpers 22 deliver production fluids from the production wells 12, 14, 16 to a manifold 20. The manifold 20 is an item of subsurface equipment comprised of valves and piping in order to collect and distribute fluid. Fluids produced from the production wells 12, 14, 16 are usually comingled at the manifold 20, and exported from the well-site through a subsea flowline 24 and the riser 38. Together, the flowline 24 and the riser 38 provide a single production line.

The production riser 38 ties back to a production facility 70. The production facility, also referred to as a “host facility” or a “gathering facility,” is any facility where production fluids are collected. The production facility may, for example, be a ship-shaped vessel capable of self-propulsion in the ocean. The production facility may alternatively be fixed to land and reside near shore or immediately on-shore. However, in the illustrative system 10, the production facility 70 is a floating production, storage and offloading vessel (FPSO) moored in the ocean. The FPSO 70 is shown positioned in a marine body 80, such as an ocean, having a surface 82 and a marine floor 85. In one aspect, the FPSO 70 is 3 to 15 kilometers from the manifold 20.

In the arrangement of FIG. 1, a production sled 34 is used. The optional production sled 34 connects the production flowline 38 with the riser 38. A flexible hose (not seen in FIG. 1) may be used to facilitate the communication of fluid between the riser 38 and the FPSO 70.

The subsea production system 10 also includes a utility umbilical 42. The utility umbilical 42 represents an integrated electrical/hydraulic control line. Utility umbilical line 42 typically includes conductive wires for providing power to subsea equipment. A control line within the umbilical 42 may carry hydraulic fluid used for controlling items of subsea equipment such as a subsea distribution unit (“SDU”) 50, manifolds 20, and trees 15. Such control lines allow for the actuation of valves, chokes, downhole safety valves, and other subsea components from the surface. Utility umbilical 42 also includes a chemical injection tubing or service line which transmits chemical inhibitors to the ocean floor, and then to equipment of the subsea production system 10. The inhibitors are designed and provided in order to ensure that flow from the wells is not affected by the formation of solids in the flow stream such as hydrates, waxes and scale. Thus, the umbilical 42 will typically contain a number of lines bundled together to provide electrical power, control, hydraulic power, fiber optics communication, chemical transportation, or other functionalities.

The utility umbilical 42 connects subsea to an umbilical termination assembly (“UTA”) 40. From the umbilical termination assembly 40, umbilical line 44 is provided, and connects to a subsea distribution unit (“SDU”) 50. From the SDU 50, flying leads 52, 54, 56 connect to the individual wells 12, 14, 16, respectively.

In addition to these lines, a separate umbilical line 51 may be directed from the UTA 40 directly to the manifold 20. A chemical injection service line (not seen in FIG. 1) is placed in both of service umbilical lines 42 and 51. The service line is sized for the pumping of a fluid inhibitor followed by a displacement fluid. During shut-in, and during a hydrate management operation, the displacement fluid is pumped through the chemical tubing, through the manifold 20, and into the production riser 38 in order to displace produced hydrocarbon fluids before hydrate formation begins.

The displacing fluids may be dehydrated and degassed crude oil. Alternatively, the displacing fluids may be diesel. In either instance, an additional option is to inject a traditional chemical inhibitor such as methanol, glycol or MEG before the displacement fluid. However, this is not preferred due to the large quantity required.

It is understood that the architecture of system 10 shown in FIG. 1 is illustrative. Other features may be employed for producing hydrocarbons from a subsea reservoir and for inhibiting the formation of hydrates. For example, a valve (shown at 37 in FIG. 3) may be placed in-line between the chemical tubing and the manifold 20 to provide selective fluid communication with the production riser 38. The system 10 may further include a water injection line (not shown) in some embodiments.

FIG. 2 is a flowchart demonstrating steps for performing a hydrate management process 200 of the present invention, in one embodiment. The method 200 employs a subsea production system, such as system 10 of FIG. 1. The system 10 includes a host production facility, an umbilical line, a manifold, at least one subsea production well, and a single production line. The method 200 enables displacement of production fluids from the single production line via an injection tubing within the umbilical line. Preferably this is done without the use of a thermodynamic hydrate inhibitor such as methanol.

In one embodiment, the method 200 first includes the step of producing hydrocarbon fluids through the production line. The production step is represented by Box 210. The method 200 is not limited as to the production rate, the hydrocarbon fluid composition, or any offshore operating parameters.

The method 200 also includes the step of shutting in the production system 220. This means that hydrocarbon fluids are no longer being produced from the subsea production wells. Any fluids already produced and residing in the production line are held in the production line. The shut-in may be either planned or unplanned. For example, an unplanned shut-in may occur where there is a subsea leak in a flowline or in a jumper connection. An unplanned shut-in may also occur where there is a failure in a separator or other equipment on the production facility.

The method 200 next includes depressurizing the subsea production system. More specifically, the method includes depressurizing the production line in the system. This depressurizing step is represented by Box 230. In normal operating conditions, the production line will carry a pressure induced by formation pressure, countered by the hydrostatic head within the production line. Depressurizing the line means that the pressure is reduced to a level that is at or above the hydrostatic head, but less than operating pressure.

The purpose of the depressurizing step 230 is to significantly reduce the solution gas concentration in the produced hydrocarbon fluids. The depressurizing step may be accomplished by shutting in the wells and/or the production line, but continuing to produce hydrocarbon fluids. As production continues and the pressure drops, the production fluids will be more and more in the form of methane and other gas phase fluids. The gas breaking out of solution may be flared at the production facility, or stored for later use or commercial sale. Preferably, recovered gases are routed to a flare scrubber.

The method 200 next includes the step of repressurizing the subsea production system. More specifically, the method includes repressurizing the production line in the system. This repressurizing step is represented by Box 240. The step 240 of repressurizing the production line means that pressure is added to the production line to a level sufficient to urge any gas remaining in the free gas phase within the production line back into solution. Of course, gas that was not in solution before the depressurization step 230 generally will not go into solution in step 240.

The repressurizing step 240 may be accomplished by pumping displacement fluid into the service line in the utility umbilical. The displacement fluid moves toward the production line without the production line being open at the production facility. The amount of pressure required to perform step 240 depends on a variety of factors. Such factors include the temperature of the sea water and the composition of the hydrocarbon fluids. Such factors also include the geometry of the production line which represents the production flowline, the production riser, the production buoy, and any flexible hoses from the riser leading to the FPSO.

The displacement fluid that is used in step 240 preferably comprises dead crude, diesel, or other hydrocarbon-based fluid having little or no methane or other hydrocarbon gases. Preferably, the displacement fluid does not include methanol. However, the displacement fluid does include a low dosage hydrate inhibitor, or “LDHI.” Low dosage hydrate inhibitors are defined as non-thermodynamic hydrate inhibitors. This means that the inhibitors do not lower the energy state of the free gas and water to the more ordered lowered energy state created by hydrate formation. Instead, such inhibitors interfere with the hydrate formation process by blocking the hydrate-growing site, thereby retarding the growth of hydrate crystals. LDHI's inhibit gas hydrate formation by coating and comingling with hydrate crystals, thereby interfering with the growth and the agglomeration of small hydrate particles into larger ones. As a result, plugging of the gas well and flowlines is minimized or eliminated.

Low dosage hydrate inhibitors may be categorized into two classes: (1) kinetic hydrate inhibitors (“KHI”), and (2) anti-agglomerants (“AA”). A KHI can prevent hydrate formation but generally does not dissolve already formed hydrates. An AA generally allows hydrates to form but keeps the hydrate particles dispersed in the fluids so they do not form plugs on the walls of a flow line. Because of their attributes, one may chose to use a combination of KHI and AA type of LDHI. Examples of KHI inhibitors include polyvinylpyrrolidone, polyvinylcaprolactam or a polyvinylpyrrolidone caprolactam dimethylaminoethylmethacrylate copolymer. Such inhibitors may contain a caprolactam ring attached to a polymeric backbone and copolymerized with esters, amides or polyethers. Another example of a suitable kinetic hydrate inhibitor is an aminated polyalkylene glycol of the formula: R¹R²N[(A)_a-(B)_b-(A)_c-(CH₂)_d—CH(R)—NR¹]_nR²

wherein:

- each A is independently selected from —CH₂CH(CH₃)O— or —(CH₃)CH₂O—;
- B is —CH₂CH₂O—;
- a+b+c is from 1 to about 100;
- R is —H or CH₃;
- each R¹and R²is independently selected from the group consisting of —H, —CH₃, —CH₂—CH₂—OH and CH(CH₃)—CH₂—OH;
- d is from 1 to about 6; and
- n is from 1 to about 4.

For example, the kinetic hydrate inhibitor may be selected from the group consisting of:

- (i) R¹HN(CH₂CHRO)_j(CH₂CHR)
- (ii) H₂N(CH₂CHRO)_a(CH₂CH₂O)_b(CH₂CHR)NH₂; and
- (iii) mixtures thereof,
  
  wherein:
- a+b is from 1 to about 100; and
- j is from 1 to about 100.

Preferably,

- each R¹and R²is —H;
- a, b, and c are independently selected from 0 or 1; and
- n is 1.

Examples of anti-agglomerants (“AA”) are substituted quaternary compounds. Examples of quaternary compounds include quaternary ammonium salts having at least three alkyl groups with four or five carbon atoms and a long chain hydrocarbon group containing 8-20 atoms. Illustrative compositions include tributylhexadecylphosphonium bromide, tributylhexadecylammonium bromide, and di-butyl di-dodecylammonium bromide. Other anti-agglomerants are disclosed in U.S. Pat. Nos. 6,152,993; 6,015,929; and 6,025,302. Specifically, U.S. Pat. No. 6,015,929 describes various examples of hydrate anti-agglomerants such as sodium valerate, n-butanol, C₄-C₈zwitterion, (zwitterionic head group with C₄-C₈tail group), 1-butanesulfonic acid Na salt, butanesulfate Na salt, alkylpyrrolidones and mixtures thereof. U.S. Pat. No. 6,025,302 describes the use of ammonium salts of polyether amines as gas hydrate inhibitors.

Other examples of AA inhibitors include the di-ester of di-butyl-di-ethanol ammonium bromide and coconut fatty acid, the dicocoyl ester of di-butyl di-isopropanol ammonium bromide and the dicocoyl ester of dibutyl diisobutanol ammonium bromide are disclosed in U.S. Pat. No. 6,214,091.

In one aspect, the low dosage hydrate inhibitor (“LDHI”) is mixed with water to form an aqueous solution (before mixture with dead crude). In one instance, the aqueous solution is between from about 0.01 to about 5% by weight of water. More preferably, the LDHI composition is from about 0.1 to about 2.0 percent by weight of water. The aqueous solution may be a brine having a density of 12.5 pounds/gallon (ppg) (or 1.5 g/cm³) or less. Such brines are typically formulated with at least one salt selected from NH₄Cl, CsCl, CsBr, NaCl, NaBr, KCl, KBr, HCOONa, HCOOK, CH₃COONa, CH₃COOK, CaCl₂, CaBr₂, and ZnBr₂.

A small amount of a thermodynamic hydrate inhibitor may be mixed with a kinetic hydrate inhibitor to form a suitable inhibitor admixture. A thermodynamic hydrate inhibitor functions to lower the energy state or “chemical potential” of the free gas and water to a more ordered lowered energy state than that of the formed hydrate and thermodynamic hydrate inhibitor. Thus, the use of thermodynamic hydrate inhibitors in deepwater oil/gas wells having lower temperature and high-pressure conditions causes the formation of stronger bonds between the thermodynamic hydrate inhibitor and water versus gas and water. Known thermodynamic hydrate inhibitors include alcohol (e.g. methanol), glycol, polyglycol, glycol ether, or a mixture thereof. Preferably, the thermodynamic inhibitor is methanol or glycol.

The method 200 also includes the step of displacing production fluids from the production line. This displacement step is represented by Box 250. The production fluids primarily comprise live hydrocarbon fluids, including methane. In order to displace fluids, the displacement fluid continues to be pumped from the service line into the production line. The production line is opened at the production facility. The live hydrocarbon fluids are then received from the production line, followed by the displacement fluid.

The step of circulating displacement fluids with LDHI takes place by injecting the displacement fluid into the injection tubing within the utility umbilical. The process of displacement with dead crude and LDHI is described through FIGS. 3 through 5. FIGS. 3 through 5 provide partial schematic views of a subsea production system 10. In each figure, a schematic view of the subsea production system 10 from FIG. 1 is provided. In each view, a utility umbilical is provided. The utility umbilical represents both a primary umbilical line 42 and a manifold umbilical line 52. In the illustrative subsea production system 10, the umbilicals 42, 52 are connected to each other at a UTA 40. Together, the umbilicals 42, 52 extend from the FPSO 70 down to the production manifold 20. The subsea umbilical 52 is fluidly connected to the manifold 20, while the utility umbilical 42 preferably ties back to the FPSO 70.

The utility umbilicals 42, 52 each represent integrated umbilicals where control lines, conductive power lines, and/or chemical lines are bundled together for delivery of hydraulic fluid, electrical power, chemical inhibitors or other components to subsea equipment and lines. The bundled umbilical lines 42, 52 may be made up of thermoplastic hoses of various sizes and configurations. In one known arrangement, a nylon “Type 11” internal pressure sheath is utilized as the inner layer. A reinforcement layer is provided around the internal pressure sheath. A polyurethane outer sheath may be provided for water proofing. Where additional collapse resistance is needed, a stainless steel internal carcass may be disposed within the internal pressure sheath. An example of such an internal carcass is a spiral wound interlocked 316 stainless steel carcass.

Where colder temperatures and higher pressures are encountered, the umbilicals 42, 52 may be comprised of a collection of separate steel tubes bundled within a flexible vented plastic tube. The use of steel tubes, however, reduces line flexibility.

It is also understood that the methods of the present invention are not limited by any particular umbilical arrangements so long as the utility umbilicals 42, 52 each include a chemical injection tubing 41, 51 therein. Umbilical 52 could be umbilicals 54 or 56 from FIG. 1. The chemical injection tubings 41, 51 are sized to accommodate the pumping of a displacement fluid. In one embodiment, the chemical tubing 51 within the umbilical 52 is a 3-inch inner diameter line, and the chemical tubing 41 within the umbilical 42 is also a 3-inch inner diameter line. However, the umbilicals 52, 42 may have other diameters, such as about 2 to 4 inches.

The injection tubings 41, 51 serve to transmit a working fluid from the FPSO 70 to the manifold 20. During normal production, i.e., without shut-in, the injection tubings 41, 51 are filled with a displacement fluid such as a dead crude. Optionally, the injection tubings 41, 51 are filled with methanol or other chemical inhibitor before the displacement fluid is injected. This helps to prevent the formation of hydrates during cold start-up.

Referring now to the production riser 38, the production riser 38 connects to the manifold 20 at one end, and ties back to the FPSO 70 at the other end. An intermediate sled and jumper line (shown at 34 and 24, respectively, in FIG. 1) may be used. The production riser 38 may be, in one aspect, an 8-inch line. Alternatively, the production riser 38 may be a 10-inch line, a 12-inch line, or other sized line. Preferably, the production riser 38 is insulated with an outer and, possibly, an inner layer of thermally insulative material. The insulation is such that the production fluids retain heat and arrive at a separator on the FPSO 70 at a temperature that is higher than the hydrate formation temperature.

A valve 37 is provided at or near the junction between the subsea umbilical 52 and the manifold 20. The valve 37 allows selective fluid communication between the chemical tubing 41 within the umbilicals 42/52 and the manifold 20. It is understood that the valve 37 may be part of the manifold 20. However, the valve 37 is shown separately for illustrative purposes. It is also understood that the valve 37 is preferably controlled remotely, such as through electrical control signals and hydraulic fluid distributed from the bundled umbilical 52.

In one illustrative embodiment, the umbilical lines 42, 52 together are 10.3 km in length, while the production riser 38 is 10.5 km in length. A 3-inch ID chemical tubing of that length may receive 300 to 375 barrels of fluid. The 8-inch production line holds approximately 1,885 barrels of fluid. Of course, other lengths and diameters for the lines 38, 41, 42, 51, 52 may be provided.

Turning now specifically to FIG. 3, FIG. 3 provides a schematic view of the subsea production system during a state of production. The injection tubings 41, 51 are filled with a displacement fluid such as a dead crude containing a LDHI. The valve 37 is in a closed position to prevent the movement of displacement fluid from the injection line 51 to the production riser 38.

In FIG. 3, a flow of produced fluids from the producing wells 12, 14, 16 has taken place. The production fluids flow from the producers 12, 14, 16, through the production manifold, and into the production riser 38. This is in accordance with step 210 of method 200.

The production riser 38 is filled with live fluids.” “Live fluids” means that the hydrocarbon fluids have a free gas phase. The fluids may be “uninhibited,” meaning that they have not been treated with methanol, glycol or other hydrate inhibitor. At the same time, the 3-inch umbilical service lines (USL) 41, 51 hold a displacement fluid such as a dead crude or diesel. In one aspect, the USL lines 41, 51 are left full of roughly 275 bbl of dead crude inhibited with a LDHI.

In FIG. 3, the valve 37 is closed. This prevents the movement of displacement fluids into the production stream. It also allows the production riser 38 to be depressurized in accordance with step 220.

After the depressurization step 230, the valve 37 is opened in order to repressurize the production riser 38 in accordance with step 240. As noted, the purpose of the repressurization step 240 is to significantly reduce the free gas concentration in the produced oil. Pressure in the system 10 is increased by pumping displacement fluid into the injection tubing 51 in the umbilical 52. This will cause free gas to be displaced out of the production flowline 24 and the riser 38. The free gas remaining in the flowline 24 and riser 38 will be driven back into solution.

After depressurization 230 and then repressurization 240 of the system 10, dead crude and LDHI are pumped into the service riser 38 to displace the uninhibited depressurized/repressurized production fluids out of the production riser 38. This is preferably done without a pig separating the fluids. This is the circulation step 250, demonstrated in FIGS. 4 and 5.

FIG. 4 provides another schematic view of the production system 10. Here, valve 37 is opened and displacement fluid is being circulated into the production riser 38. The displacement fluid is displacing production fluids up to the FPSO 70. Displacement fluid will substantially displace production fluids from the production flowline 24 and production riser 38 until both the injection tubing 51 in the umbilical 52 and the production riser 38 are substantially filled with the displacement fluid. This is done without a pig separating the fluids. The circulation step 250 also serves to displace any remaining free gas in the production riser 38.

During displacement, the pump velocity should be high enough to create laminar flow within the production riser 38. For example, for a 10-inch line, a pump rate of 5,000 barrels per day should be adequate. Displacement at relatively low velocity without a pig is inefficient in that it allows significant mixing and bypassing of production fluids by the displacing fluid.

It is noted from FIGS. 3 and 4 that the production riser 38 runs “uphill” from the well manifold 20 to the FPSO 70. The only exception pertains to the use of a riser base spool, a flexible jumper low point (not shown), and possibly some bumps along the flowline due to ocean floor contour. Because of the gradient, when a well is shut in for an extended period of time, e.g., 4 or more hours, the produced fluids in the production riser 38 will largely segregate into layers of (1) water, (2) live oil and (3) gas, although variable terrain, emulsions or foaming may impede segregation. The behavior of the interfaces between these layers is noted as follows:

1. Live oil and gas interface. Due to the uphill geometry and the lower density of gas as compared to the live oil, most gas naturally flows towards the FPSO 70. Some gas is trapped at high points in the system 10. As pressure increases, the crude in the produced fluids may absorb the gas and transport it to the FPSO 70.

2. Water and live oil interface. Due to the uphill geometry and the lower density of live oil as compared to the water, most live oil naturally flows towards the FPSO 70.

3. Cold dead crude/production fluid interface. At an average rate of 5,000 bpd in a 10-inch line, the dead crude Reynolds number is 327, which indicates laminar flow. Therefore, there should be relatively low mixing of dead crude and production fluids. However, as noted, pump velocity should be relatively high.

FIG. 5 is another schematic view of the subsea production architecture 10 of FIG. 1. In this view, both the injection tubing 51 in the umbilical 52 and the production riser 38 are substantially filled with the displacement fluid. No live gas should remain in the production system 10. Complete displacement of “live fluids” has taken place.

It is noted that during the displacement step 250 demonstrated in FIGS. 4 and 5, new production fluids are not being circulated into the production riser 38. This means that warm subterranean fluids are not being circulated into the production system 10. Instead, cold dead crude is being circulated. This period of “shut-in” in which new production fluids are not being moved through the production riser 38 is referred to as a “cool down” time. The cool down time should be as short as possible to avoid hydrate formation. In one aspect, the cool down time is from 4 to 10 hours, but typically it is about 8 hours.

During the cool down time, but before completion of the displacement operation, live production fluids remain in the insulated production riser 38. The insulation around the production riser 38 helps keep the uninhibited production fluids in the production flowline 24 and riser 38 above the hydrate formation temperature. Remedial operations in the subsea production system take place within the “cool down” time.

Returning to FIG. 5, as displacement of fluids from the riser 38 continues, produced fluids are urged towards the production facility 70. Arrival pressure should be no higher than normal operating pressure. For example, operating pressure may be about 18 bars (abs.). The arrival pressure preferably is reduced to roughly 16 bars (abs.), beginning about 30 minutes after the displacement step 240 begins. This increases the dead crude rate and displacement efficiency. Preferably, no arrival choking is performed as this could decrease the dead crude rate and displacement efficiency. This is in contrast to the procedure used when a pig is in the line for performing full production loop displacement.

In one aspect, the maximum allowable dead crude pumping system pressure measured at the FPSO 70 as fluids enter the umbilical is approximately 191 bars (abs.), as follows:

- When a well is filled with gas, the gas gradient for the shut-in tubing pressure is 246 bars (abs.). This is based upon the density of the fluid being produced in the wellbore.
- 55 bars is added to account for performing scale squeeze procedures to further pressurize the flowline, producing a 301 bar (abs.) flowline pressure rating.
- A dead crude gradient from the well manifold 20 to the FPSO 70 is 100.7+9.6=110.3 bars (abs.). This is based upon the density of the fluid, which is used to calculate the static head of the fluid column in the service umbilical line.
- Assuming the FPSO dead crude pump dead heads (meaning that the pressure of the pump achieves a zero flow rate), the maximum allowable discharge pressure is 301−110=191 bars (abs.).

The numbers provided in this example are merely illustrative. The operator must consider the designed pressure of the subsea equipment when generating a pump discharge pressure at the FPSO 70. Stated another way, the pump displacement pressure should not exceed the maximum allowable pressure of the subsea equipment. At the same time, it is desirable to maximize displacement velocity without exceeding the maximum allowable design pressure of the subsea equipment.

The FPSO 70 processes displacement fluids in the same manner as would be done if performing displacement by pigging with dead crude. The fluids are preferably received into a high pressure test separator (not shown). The recovered liquids are preferably stored in a storage tank such as a dedicated tank for fluids that are “off-spec” for sales. Recovered gases may be routed to a flare scrubber. As the displacement step 250 continues, the separator will receive and process an increasing percentage of dead oil. Towards the end of the process, completely dead crude will flow into the separator.

It is noted that the dead crude in the service line 51 within the umbilical line 52 will be at ambient sea temperature, which is below the hydrate formation temperature of the uninhibited production fluids in the production riser 38. As a result, it is expected that the dead crude will cool the production fluids to temperatures below the uninhibited hydrate formation temperature. However, because of the depressurization 230 and repressurization 240 steps, there will be virtually no free gas phase in the system 10 once displacement begins. Therefore, the risk of hydrate plugging in the production riser 38 after displacement is low.

In addition, the LDHI in the cold dead crude displacement fluid will suppress hydrate blockage. The mechanism will be either anti-agglomeration or kinetic inhibition depending on the type of LDHI used. This further reduces the risk of hydrate plugging in the production riser 38.

Preferably, the displaced hydrocarbon fluids are monitored at the production facility 230. This is represented by Box 260 in FIG. 2.

FIG. 6 is a graph showing the monitoring step 260. More specifically, FIG. 6 demonstrates water content in a production line during displacement, as a function of dead crude displacement rate. FIG. 6 was generated as a result of a simulation that was conducted to demonstrate displacement results from a possible set of operational parameters.

The simulation assumed that the production line 24/38 was an 8-inch line. Prior to shut-in, the production line 24/38 was tied back to subsea producer wells having a 72% watercut in year 7. The production wells were shut-in for 8 hours. Time “0” on the plot represents the beginning of the displacement process.

Five lines are shown indicating potential injection or displacement rates. Those are:

- 3.0 kbpd (line 610);
- 4.0 kbpd (line 620);
- 5.0 kbpd (line 630);
- 6.8 kbpd (line 640); and
- 9.0 kbpd (line 650).

Displacement at the lowest rate of 3,000 bpd produced the poorest results, while displacement at the highest rate of 9,000 bpd produced the best results. In the line 610 for the lower displacement rate (3,000 bpd), 200 barrels of water remained in the sweep even after 25 hours of pumping. In contrast, in the line 650 for the highest displacement rate (9,000 bpd), substantially all of the water had been swept after 10 hours of pumping.

As noted above, it is believed that displacement at relatively low velocities or injection rates without a pig is inefficient. A lower injection rate appears to allow for significant mixing and bypassing of production fluids by the displacing fluid. FIG. 6 confirms that a high pumping or injection rate is therefore preferred.

The dead crude injection rate will vary during displacement. The pumping rate is dependent on the contents of the USL 51, the flowlines, and the riser 38. Preferably, the dead crude pumping system is set to inject into the USL 51 from the production facility 70 at the maximum allowable pressure. In one aspect, the maximum pumping rate will range from 5,000 to 8,000 barrels per day (5 to 8 kbpd).

Returning to FIG. 2, the method 200 optionally includes repeating steps 230 through 260. This is represented by Box 270. The steps of depressurization 230, repressurization 240 and displacement 250 may be done once or multiple times during a process of hydrate mitigation to render the production system 10 safe from hydrate blockage.

It was desired to model and compare gas phase content with water phase content as a function of time. Therefore, compositional simulations were performed using OLGA™ software. OLGA™ is a transient pipeline program that simulates fluid flow. The compositional OLGA™ simulations (as opposed to standard OLGA™ simulations) are able to predict phase equilibrium more accurately than non-compositional OLGA simulations.

The results of the simulation are found in FIG. 7. FIG. 7 is a graph comparing aqueous phase content and gas phase content in a production line during displacement, as a function of time. Four lines are shown indicating different phase contents:

- Line 710 represents water or aqueous phase content for a compositional simulation;
- Line 720 represents water or aqueous phase content for a black oil simulation;
- Line 730 represents gas phase content for a compositional simulation; and
- Line 740 represents gas phase content for a black oil simulation.

Compositional and black oil models present alternative simulation techniques. Each of these models may be used to calculate the vapor-liquid equilibrium of the fluid and the properties of the vapor and liquid phases. The compositional model is considered to be a more rigorous and computationally intensive model than the black oil model. Black oil models require less data and less computation, and are generally used if it is believed that the accuracy will be comparable to the compositional model.

First, comparing lines 710 and 720 indicating aqueous phase content, it can be seen that the compositional simulation 710 produced results markedly similar to the standard OLGA™ results 720 when black oil properties were used in the standard OLGA™ simulation. Line aqueous phase content over time was very similar. In this respect, after 16 hours of pumping, the aqueous phase content was 47 barrels for both line 710 and 720.

Second, comparing lines 730 and 740 indicating gas phase content, it can be seen that the compositional simulation 730 produced results similar to the standard OLGA™ results 740 when black oil properties were used in the standard OLGA™ simulation. However, a significant deviation occurred at about 12 hours.

By the 16 hour point, the gas phase content using standard OLGA™ results 740 was 46 barrels. However, the compositional simulation 730 was only one to four barrels. Thus, the line gas phase content predicted by the compositional simulation was significantly less than standard OLGA™ after 12 hours. The compositional simulation 730 predicts that the final free gas phase volume drops as low as one barrel. Line 740 of FIG. 7 confirms a substantial displacement of gas from the production system as of about 15 hours.

As can be seen, improved methods for subsea hydrate management in a single production flowline system are provided. For example, at least one method provides for hydrate management utilizing a chemical injection line in an umbilical for injecting a low density hydrate inhibitor. Still further, another method discloses displacement of a single production line via a service line in the subsea umbilical without, in some embodiments, the use of a thermodynamic inhibitor such as methanol, and without, in some embodiments, the use of a pig. While it will be apparent that the invention herein described is well calculated to achieve the benefits and advantages set forth above, it will be appreciated that the invention is susceptible to modification, variation and change without departing from the spirit thereof.

Method For Managing Hydrates In Subsea Production Line

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