Separation of asphaltenes

An asphaltenes separation system comprising a flocculant feed system configured to add a flocculant to a production fluid to flocculate asphaltenes in the production fluid, and an asphaltenes separator configured to remove flocculated asphaltenes from the production fluid.

FIELD

Disclosed techniques relate to oil and gas production, and more particularly, to subsea oil and gas production. Still more particularly, the disclosed techniques relate to the removal of asphaltenes from oil and gas production operations.

BACKGROUND

This section is intended to introduce various aspects of the art, which may be associated with exemplary 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.

Asphaltenes may be problematic in oil in production fluids. Asphaltenes are generally dissolved in production fluids at typical reservoir pressures and temperatures. However, the asphaltenes may precipitate and drop out of production fluid as pressure is reduced in the conveyance and processing of the production fluid. Asphaltene deposits may foul piping and equipment, including wellhead equipment, pipelines, surface facilities, process piping, downstream refining operations, and so forth. Conventional remediation includes solvent washing or mechanical treatment of piping and equipment to remove the deposited asphaltenes. Remediation may alternately or additionally include the addition of chemical dispersants to the production fluid to hinder precipitation of the asphaltenes. These solutions carry certain disadvantages, for example, a solvent wash may require several hours of downtime and may introduce significant cost and environmental concerns associated with the solvents. Further, it may be difficult to consistently add chemical dispersants to the production fluid to avoid deposition because the operating region of precipitation of the asphaltenes may vary and, in some instances, may occur prior to addition of the chemical dispersant. In part due to this lack of consistent asphaltenes, the efficiency of the treatment may vary as process factors such as composition, pressure/temperature profiles, etc., change.

As a result of the above, a need exists for a technique to minimize or eliminate asphaltene deposits that does not suffer the drawbacks of the conventional remediation approach of adding chemical dispersants.

SUMMARY

This disclosure includes an asphaltenes separation system comprising a flocculant feed system configured to add a flocculant to a production fluid to flocculate asphaltenes in the production fluid, and an asphaltenes separator configured to remove flocculated asphaltenes from the production fluid.

This disclosure also includes a separation system comprising a flocculating agent feed system configured to add a flocculating agent to a conduit conveying production fluid from a subsea wellhead, wherein the production fluid comprises hydrocarbon, and an asphaltenes separator operationally coupled to the conduit and configured to receive the production fluid, remove flocculated asphaltenes from the production fluid, discharge an asphaltenes stream comprising the flocculated asphaltenes, and discharge a product comprising the production fluid.

This disclosure further includes a method for separating asphaltenes from a production fluid comprising receiving the production fluid from a wellhead, the production fluid comprising hydrocarbon and asphaltenes, adding a flocculation stream to the production fluid, mixing the flocculation stream with the production fluid to precipitate asphaltene flocs flowing in the production fluid, and separating the asphaltene flocs from the production fluid.

DETAILED DESCRIPTION

In the following detailed description section, specific embodiments of the present techniques are described. 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 exemplary 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.

As used herein, the term “exemplary” means serving as an example, instance, or illustration. Any embodiment described herein as “exemplary” is not to be construed as preferred or advantageous over other embodiments.

As used herein, the term “gas” is used interchangeably with “vapor,” and means a substance or mixture of substances in the gaseous state as distinguished from the liquid or solid state. Likewise, the term “liquid” means a substance or mixture of substances in the liquid state as distinguished from the gas or solid state. As used herein, “fluid” is a generic term that may include a liquid, a gas, or vapor, or any combination thereof.

As used herein, the term “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, hydrocarbons generally refer to organic materials that are transported by pipeline, such as any form of natural gas or oil. A “hydrocarbon stream” is a stream enriched in hydrocarbons by the removal of other materials such as water, solids, and/or any additive.

As used herein, the term “natural gas” refers to a multi-component gas obtained from a crude oil well (associated gas) or from a subterranean gas-bearing formation (non-associated gas). The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (C1) as a significant component. Raw natural gas will also typically contain ethane (C2), higher molecular weight hydrocarbons, which may be collectively referred to herein as “heavy hydrocarbons,” one or more acid gases (such as carbon dioxide, hydrogen sulfide, carbonyl sulfide, carbon disulfide, and mercaptans), and minor amounts of contaminants such as water, nitrogen, and crude oil.

As used herein, the term “pressure” is the force exerted per unit area by the gas on the walls of the volume. Pressure can be shown as pounds per square inch (psi).

“Atmospheric pressure” refers to the local pressure of the air. “Absolute pressure” (psia) refers to the sum of the atmospheric pressure (14.7 psi at standard conditions) plus the gauge pressure (psig). “Gauge pressure” (psig) refers to the pressure measured by a gauge, which indicates only the pressure exceeding the local atmospheric pressure (i.e., a gauge pressure of 0 psig corresponds to an absolute pressure of 14.7 psia). The term “vapor pressure” has the usual thermodynamic meaning. For a pure component in an enclosed system at a given pressure, the component vapor pressure is essentially equal to the total pressure in the system.

As used herein, the term “production fluid” refers to a liquid and/or gaseous stream removed from a subsurface formation, such as an organic-rich rock formation. Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids. For example, production fluids may include, but are not limited to, oil, natural gas and water.

As used herein, the term “substantial” 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 in some cases depend on the specific context.

As used herein, the term “well” or “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. The terms are interchangeable when referring to an opening in the formation. A well may have a substantially circular cross section, or other cross-sectional shapes (for example, circles, ovals, squares, rectangles, triangles, slits, or other regular or irregular shapes). Wells may be cased, cased and cemented, open-hole well, etc., and may be any type, including, but not limited to, a producing well, an experimental well, an exploratory well, or the like. A well may be vertical, horizontal, or any angle between vertical and horizontal (a deviated well), for example a vertical well may include a non-vertical component.

In subsea oil and gas production operations, asphaltenes in production fluids can cause flow assurance issues, such as the fouling of flow lines and process equipment. Prior art approaches to solving the problem of asphaltenes included using dispersants to prevent agglomeration. Techniques described herein including using flocculants to encourage or promote the flocculation of asphaltenes in comparatively small agglomerations rather than dispersal. When flocculated, asphaltene “stickiness” may be decreased. Advantageously, such techniques may accommodate size and weight restrictions imposed on deep-water processing units. In general, the techniques described herein may achieve removal of flocculated asphaltenes molecules from production fluids. The flocculated asphaltene removal may improve the flow assurance aspect of the production fluid by reducing asphaltenes fouling of piping and equipment.

Asphaltenes are polar colloidal particles typically with relatively large surface area. Asphaltene particles may agglomerate. In the presence of a flocculant, asphaltene particles may bond and form flakes or clusters having a reduced surface area in comparison to agglomerated asphaltenes. Therefore, the flocculated asphaltenes may have a reduced activity or a reduced tendency to stick to pipewall or process equipment. Including sand in the production fluid of the flocculated systems may increase the effectiveness of asphaltene flocculation, e.g., by providing a site for flocculation to occur.

In some embodiments, the production fluid having the flocculated asphaltenes may be conveyed to surface facilities where the flocculated asphaltenes are separated from the production fluid. The motive force for transport to the surface may be, for example, wellhead pressure. In other embodiments, the flocculated asphaltenes may be separated from the production fluid at the subsea level such as near the subsea wellhead. In such examples of subsea separation, a production fluid substantially free of asphaltenes may discharge from the subsea separation system and may be transported (e.g., in a conduit) from the subsea wellhead area to surface facilities. Prior to reaching the surface facilities, the production fluid may be subjected to additional subsea processing, such as water removal. The motive force for conveyance of the processed production fluid to the surface may be, for example, the wellhead pressure. As discussed below, the separated and removed asphaltenes from the production fluid may be transported (e.g., in another conduit) from the subsea separation to the surface facilities. In particular examples, water or a hydrotransport may be employed to facilitate conveyance of the separated solid asphaltenes particles or clusters to the surface.

FIG. 1is a schematic diagram of an asphaltenes separation system100operationally coupled to a source102, e.g., a subsea wellhead, of a fluid104, e.g., a production fluid, having asphaltenes. The fluid104may comprise some sand. In another example, the source102is a high-pressure storage of oil, and the fluid104is oil. The fluid104may generally discharge from the source102through a conduit to a downstream separator.

In the illustrated embodiment, the asphaltenes separation system100adds a flocculation stream106comprising a flocculation agent to the fluid104, e.g., via the conduit conveying the fluid104. Therefore, the interface for the addition of the flocculation stream106to the fluid104may be, for example, a conduit tee.

In certain embodiments, the flocculation stream106is a flocculant or flocculating agent, such as a polymeric flocculating agent, that promotes flocculation and agglomeration of asphaltenes in the fluid104. The flocculating agent may be anionic cationic, or nonionic. The flocculating agent may comprise an oil-soluble polymer, a water-soluble polymer, or both. Suitable water-soluble flocculants include high-molecular weight polyacrylamides (PAM), hydrolyzed polyacrylamide (HPAM), etc., and nonionic polyethylene oxide homopolymer. Water-soluble flocculant(s) may be dissolved in water before addition or injection. In embodiments using oil-soluble flocculants, the oil-soluble flocculants may be mixed with oil prior to addition or injection to the production fluid. The mixing of the flocculant with oil or water may be performed in a flocculant feed system or upstream of the flocculant feed system.

Further, another production fluid (e.g., having oil and gas) may be added to the flocculation stream106to assist in blending the fluid104. Such gas may be natural gas, methane, inert gas, or other gas. Such additions may change the overall oil composition in the production fluid, for example, to promote precipitation and/or flocculation of asphaltenes. However, while adding gas may facilitate asphaltene precipitation, the addition of gas to the production fluid may increase the bubble point and asphaltenes onset pressure (AOP) of the production fluid in certain instances. In certain examples, the composition of the injection gas may be adjusted to reduce an associated increase in production-fluid bubble point and AOP, and to advance precipitation of the asphaltenes.

Sand may be added along with flocculant to promote the flocculation of asphaltene molecules or “flocs.” The sand may be selected to obtain various performance characteristics, e.g., varying the sand grain size and/or quantity of the added sand to reduce sedimentation or plugging in the flowline, to improve flocculation, etc. The sand content should generally not be too high which may degrade or break the flocs due to the friction between large particles, for example. Further, excessive amounts of sand could adversely affect flow of the production fluid. Further, in cases with the fluid104having greater amounts of sand that inhibit the asphaltenes from precipitating or dropping out of suspension, sand may be removed.

Stickiness of asphaltenes can be due to high surface activity, which may be proportional to the surface area of the asphaltenes particles. The activity of the solid asphaltenes and likelihood that asphaltenes stick to walls of conduits or equipment may be decreased by reducing the available surface area of the asphaltenes particles. The flocculant may facilitate formation of larger particles or clusters of the asphaltenes by binding asphaltene particles to itself, thereby reducing the available surface area, and thus stickiness, of the asphaltenes. Any sand present may provide anchor sites to further promote agglomeration and reduction of surface area and stickiness of the asphaltenes particles.

In some examples, the addition rate of the flocculation stream106, in some embodiments a portion thereof, e.g., flocculant, sand, gas, etc., may be modulated or regulated by a control system when adding the flocculation stream106to the fluid104. The control system may include control valves, instrumentation, computers, computer memory, a processor, and so forth. The control system may adjust the flow rate or addition rate of the flocculation stream106in response to the effectiveness of the separation110operation, the level of any asphaltenes fouling of piping and equipment, and so on. The addition rate of the flocculation stream106may be adjusted to promote the desired morphology of the formed solids having asphaltenes, e.g., to reduce the active surface area of the asphaltenes, to provide voids (for production fluid) in the asphaltenes clusters, to promote a density difference between the solid asphaltenes versus the production fluid, etc. Mixing the fluid104and the flocculation stream106may create a mixture108.

In concert with, or in lieu of, the addition of a flocculation stream106, a controlled pressure drop of the fluid104may be implemented (not shown) to induce precipitation of asphaltenes. The pressure reduction may place the fluid104into an operating “unstable” region with respect to asphaltenes and thus promote precipitation of solid asphaltenes particles in the fluid104. The pressure reduction may be implemented by a reduction in diameter of the conduit conveying the fluid104. The pressure reduction may be implemented via a restriction orifice, valve, and so forth. In examples of a valve employed to provide for a pressure drop of the fluid104, the valve may be a choke valve. In cases with the source102as a wellhead, the choke valve may be a second choke valve in addition to a choke valve typically employed at the wellhead.

The mixture108is conveyed to a separator110. Flow shear forces in the conduit transporting the mixture108may advance mixing of components in the mixture108to further promote formation of asphaltenes particles from solution or suspension. Additionally, an inline mixer (not shown) such as a static mixer or agitated vessel may further promote mixing of the mixture108in route to the separator110. In general, a unit operation such as an inline mixer, vessel, agitated vessel, and the like, may optionally be applied to give additional residence time and mixing of the mixture108in route to the separator110. Further, the separator110may serve as a pressure reduction device to provide for a controlled pressure drop, as discussed above.

The separator110removes asphaltenes112from the mixture108and fluid104. The separator110may be a hydrocyclone or other type of separator that separates asphaltenes112solid particles or clusters from the fluid104. Also, the separator110may include more than one separator. Further, the separator110may also remove sand with the asphaltenes. Thus, the asphaltenes112may include sand. Whether performed subsea or at the surface, the separation may be promoted by differences between density of the flocculated asphaltenes clusters versus density of the production fluid. Further, certain sizes of the flocculated asphaltenes may promote separation from the production fluid. The asphaltenes clusters can be engineered to have a particular density and size. Indeed, the types and dosages of the flocculant may be selected to give a desired morphology of the flocculated asphaltenes clusters. Exemplary values and ranges of specific gravity for components in the production fluid include about 0.8 to about 1.1 for oil, about 0.8 to about 1.1 or about 1.0 for water, about 1.5 to about 3 or about 2.5 for sand, and about 0.8 to 1.1 for asphaltenes. Such exemplary values and ranges for specific gravity are not intended to limit embodiments of the present techniques.

The product114from the separator110may be a more purified fluid104, or a fluid104substantially free of asphaltenes or with a reduced amount of asphaltenes. In cases of the fluid104as production fluid, the product114from the separator110may be a more purified production fluid, or a production fluid substantially free of asphaltenes or with a reduced amount of asphaltenes. The separator product114as production fluid may include oil, gas, other hydrocarbons, water, and so on. In the example of the source102as a subsea wellhead, the separator110may be disposed, located, or placed subsea near the wellhead, or the separator may be disposed at surface facilities. The motive force to and through the separator110may include source102pressure, a pump or other motive device, or other motive forces.

FIG. 2is a schematic diagram of an asphaltenes separation system200, e.g., the asphaltenes separation system100ofFIG. 1, coupled to a subsea wellhead202discharging production fluid204. Like numbered items are as described with respect toFIG. 1. In the example ofFIG. 2, the wellhead202may be analogous to the source102ofFIG. 1, the production fluid204may be analogous to the fluid104ofFIG. 1, and the separation feed206may be analogous to the mixture108ofFIG. 1.

The asphaltenes separation system200receives the production fluid204from the subsea wellhead202. The separation system200adds a flocculation stream106to the production fluid204to form asphaltenes particles in the production fluid204. The mixture of production fluid204having solid asphaltenes and any residual flocculation stream106is sent as a separation feed206to a separator110to remove the precipitated or flocculated asphaltenes from the production fluid204. In the illustrated embodiment, the separator110is located on a collection platform208, such as a floating production storage and offloading (FPSO) unit, at the surface210. The collection platform208may be anchored to the sea floor by a number of tethers, and may receive production fluid from multiple subsea wellheads on the ocean floor. In alternate embodiments, the separator110may optionally be disposed subsea within the scope of this disclosure.

Onboard the collection platform208, the separator110removes asphaltenes from the separation feed206and production fluid204. The wells underlying the wellheads may include single wellbores or multiple, branch wellbores. The collection platform208may have equipment for dehydration, purification, and other processing, such as liquefaction equipment to form purified hydrocarbons for storage in vessels. The collection platform208may transport processed production fluid and hydrocarbon to shore facilities by pipeline (not shown).

FIG. 3is a schematic diagram of a separation system300, e.g., the separation system200ofFIG. 2, operationally coupled to a wellhead202. Like numbered items are as described with respect toFIG. 2. The separation system300receives a production fluid204through a conduit from the wellhead202. The separation system300may include a flocculant feed system302, e.g., comprising a flocculation stream106ofFIGS. 1 and 2, that adds a flocculating agent or flocculant304to the conduit (e.g., pipe) conveying the production fluid204from the wellhead202. The conduit conveying the production fluid from the wellhead202may have an optionally selected nominal diameter, e.g., between about 6 inches to about 24 inches, between about 8 inches to about 12 inches, or about 10 inches, and the conduit conveying the flocculant304to the production fluid204may have an optionally selected nominal diameter, e.g., between about 0.5 inches to about 8 inches, between about 1 inch to about 4 inches, or about 2 inches. Thus, a conduit tee of 10-inch by 2-inch, or a 2-inch tap on the 10-inch line, may be employed as the interface of the flocculant304addition to the production fluid204.

The flocculant feed system302, which may be referred to as a flocculant feed structure, a flocculant feed apparatus, a flocculant feed complex, or a flocculant feed arrangement, may receive a flocculant304′ from intermediate storage on a collection platform306(e.g., a FPSO unit), e.g., residing on a surface308. In some embodiments, the flocculant304′ may be substantially the same as the flocculant304or may comprise a premix flocculant solution. In other embodiments, the flocculant feed system302may perform some mixing, processing, or addition, e.g., of water, oil, and/or sand, to the flocculant304′ to produce the flocculant304.

Adding the flocculant304to the production fluid204creates a separation mixture or feed310that may be sent to an asphaltenes separator312. Flow shear forces in the conduit conveying the separation feed310to the separator312may advance mixing of the production fluid204with the flocculant304. In addition, the separation feed310may optionally (depicted with dashed lines) flow through a mixer314to further advance mixing of the production fluid204with the flocculant304. The mixer314may be an agitated vessel or an inline mixer such as a static mixer, and so forth. The flow shear forces and the optional mixer314may provide mixing energy of flocculation, thereby impacting the number of particle collisions between asphaltenes and the efficiency of the collisions. In some examples, the mixing can be adjusted to produce a desired amount of asphaltenes flocculated particles. An insufficient mixing of the production fluid stream204and flocculant304can impair the formation of flocs because there will be fewer contacts between asphaltenes particles. Conversely, over-mixing the particles may impair the formation of flocs due to excessive collisions.

As a result of the asphaltenes flocs having voids filled with production fluid204, and the clusters having a similar density to the production fluid204, the production fluid204stream may optionally bypass or avoid subsea separation and instead be processed to remove the solid asphaltenes at surface facilities. However, at separation, whether subsea or at a surface facility, a density difference between the asphaltenes solids versus the production fluid204may be beneficial.

The separator312may be a separation system, a separator system, a plurality of separators, a separator structure, a separator apparatus, a separator complex, a separator arrangement, and so forth, and may comprise a hydrocyclone, a filter or filtration system, a clarifier, or a settling system. The product discharging from the separator312may be a wet product316having production fluid including water and a reduced amount of or substantially no asphaltenes. The removed asphaltenes stream318may include sand and may be conveyed to the platform306for additional processing and/or storage.

The wet product316may be optionally sent to a water separator320. The water separator320may be an oil/water separator that removes a water stream322from the production fluid and discharges an at least partially dehydrated product324including the production fluid with less or substantially no water. Examples of the water separator320include a cyclone, centrifugal system, filter, and so on. The at least partially dehydrated product324(e.g., production fluid) may be conveyed to the platform306or other surface facilities for additional processing and/or storage. In particular, the water stream322may be a water source for a hydrotransport of the particles and clusters of asphaltenes stream318(and, in some embodiments, sand) from the asphaltenes separator312to the platform306or to other surface facilities for additional processing and/or storage. The combined stream of asphaltenes stream318and water stream322is indicated by the reference numeral326.

FIG. 4is a schematic diagram of the flocculant feed system302ofFIG. 3. The flocculant feed system302may include a feed vessel400, pump402, e.g., a centrifugal pump, positive displacement pump, etc., and a control valve404, and may rely on a control system406to provide control signals to the control valve404and/or the pump, e.g., to modulate addition of the flocculant304. The control valve404may actuate in response to a control signal from the control system406based on reaching a predetermined feed set point, a back pressure, or another sensed parameter. The control system406may be a distributed control system (DCS), programmable logic controller (PLC), or other type of computing system and instrumentation. The control system406may facilitate management and control of other subsea and platform operations in addition to the flocculant feed system302.

A level408of flocculant304may be maintained in the feed vessel400, e.g., as controlled by the control system406. The feed vessel400may be one or more feed vessels that receive one or more flocculant304′ types from the platform306ofFIG. 3.

In some embodiments, oil and/or water may be added to the feed vessel400, as indicated by the arrow410, to mix with flocculant304′ in the vessel400. If so, the vessel400may have an agitator (not shown) to promote mixing of the oil and/or water with the flocculant. In another example, the contents of the feed vessel400having the added oil and/or water may be circulated through a recirculation loop (not shown) from the pump402discharge to the vessel400to mix the oil and/or water with the flocculant.

In examples where more than one flocculant304′ is utilized, the different flocculant304′ types may be added together from the feed vessel400to the downstream production fluid204. On the other hand, the different flocculant304′ types may be added separately from respective feed vessels400to the downstream production fluid204. If so, the different flocculant304types may be added at different locations of the conduit conveying the production fluid204. These and other variations will be apparent to those of skill in the art and are considered within the scope of the present disclosure.

FIG. 5is a block flow diagram of a method500for separating asphaltenes from a production fluid. In various embodiments, the systems200and300discussed above with regard toFIGS. 2 and 3, respectively, may be used to implement the method500. At block502, the method includes receiving a production fluid discharging from a wellhead. The production fluid may including hydrocarbon, such as oil and natural gas, and also asphaltenes, sand, water, and so forth. The wellhead may be a subsea wellhead, an on-shore wellhead, and so on. At block504, a flocculating agent or flocculant is added to the flowing production fluid. The flocculant may be added via a flocculant conduit (e.g., umbilical, tubing, small piping, etc.) conveying the flocculant to a relatively large conduit flowing the production fluid. At block506, the flocculating agent or flocculant is mixed with the production fluid. In some examples, adequate mixing may be provided via flow shear forces of the fluid flowing in the conduit, one or more mixers, e.g., inline mixers, may be employed agitators, or combinations thereof. The separator may be disposed at a specified distance downstream from the flocculant injection point selected to permit adequate mixing time and/or flow length.

The conduit and any mixer may be configured to give the level of mixing and residence time for the asphaltenes to reach a desired level of flocculation within the production fluid stream. For an in-line agitated vessel, the volume of the vessel and the speed of the agitator, and the like, may be specified.

At block508, the asphaltenes are separated from the production fluid. The asphaltenes can be separated using many different techniques, including, for example, a hydrocyclone. This separation can be performed subsea or at the surface. If the separation is performed at the surface, the production fluid with flocculated asphaltenes is conveyed to surface facilities. On the other hand, for subsea separation of the flocculated asphaltenes from the production fluid, a separator is disposed subsea to separate the flocculated asphaltenes from the production fluid stream. In general, the production fluid is processed to achieve separation of asphaltenes from the production fluid.

At block510, water can optionally be separated from the production fluid. This separation can be performed, for example, also through a cyclone, or a filter, and so forth. This additional separation can occur subsea or at the surface. In certain embodiments, the water is separated from the production fluid already processed to remove asphaltenes, as at block508. In some examples, the separated water is utilized in the hydrotransport of asphaltenes.

At block512, the flocculated asphaltenes are transported. For subsea separation of flocculated asphaltenes, the asphaltenes may be transported to a floating platform at the surface. As indicated, the water separated at block510may be utilized in the hydrotransport of the asphaltenes. The flocculated asphaltenes may be transported to storage or additional processing.

At block514, the processed production fluid is transported. For subsea separation of flocculated asphaltenes from the production fluid, the production fluid with less or substantially no asphaltenes may be transported to the surface. For additional subsea separation of water from the production fluid, the production fluid with less or no water may be transported to the surface. The production fluid may be transported to surface facilities for additional processing and storage. The wellhead pressure may be used as the motive force for conveying the production fluid. Further, pumps may be optionally employed to provide motive force for conveyance of the production fluid.

At block516, the addition rate of flocculant to the production fluid is adjusted in response to flocculation and separation performance. For example, in response to insufficient flocculation of asphaltenes and insubstantial agglomeration of asphaltenes, additional flocculating agent can be added to the system to induce more flocculation of asphaltenes. Moreover, the addition rate of the flocculant may be adjusted to alter morphology of the flocculated asphaltenes, to increase efficiency of separation of the flocculated asphaltenes from the production fluid in a separator, and so forth. A control system, pump, control valve, and the like, may facilitate adjustment of the addition rate of the flocculant to the production fluid.

The process flow diagram of the method ofFIG. 5is not intended to indicate that the actions of the method500are to be executed in any particular order, or that all of the actions of the method500are to be included in every case. Further, any number of additional actions not shown inFIG. 5may be included within the method500, depending on the details of the specific implementation.

FIG. 6is a diagrammatical representation of an example of the separator312ofFIG. 3. In this example, the separator312is a hydrocyclone. The separation feed310, e.g., the separation feed310ofFIG. 3, having the production fluid204with flocculated asphaltenes enters the separator312. The entry of the separation feed310to the hydrocyclone separator312may be a tangential entry, as indicated by the curve600. In other words, the hydrocyclone may have, for example, a feed nozzle configured to give a tangential entry. In the hydrocyclone, the flocculated and agglomerated asphaltenes (and any sand) are separated from the production fluid204, e.g., via centrifugal forces and the density difference of the asphaltenes and sand clusters versus the production fluid204. In the illustrated embodiment, a product316of the production fluid with less or substantially no asphaltenes discharges overhead from the hydrocyclone. The flocculated and agglomerated asphaltenes and sand clusters may be discharged as a remove asphaltenes stream318, e.g., from a bottom portion of the hydrocyclone.

The diagram ofFIG. 6is not intended to indicate that the separator312is to include all of the features shown inFIG. 6. Further, any number of additional features may be included within the separation system600, depending on the details of the specific implementation. Moreover, again, a hydrocyclone is only given as an example of a separator312inFIG. 6. Other types of separators and unit operations may be employed as the separator312to remove flocculated and agglomerated asphaltenes (and sand) from the production fluid204.

The conditions for inducing precipitation and flocculation of asphaltenes in production fluid can be influenced and advanced by the techniques discussed herein. Placing the production fluid into an unstable region of temperature and pressure for asphaltenes precipitation can encourage asphaltenes particles to precipitate in the production fluid.

Further, the addition of flocculant to the production fluid can promote precipitation via flocculation of asphaltenes particles, including with the production fluid in a traditional stable region of pressure and temperature not typically giving asphaltenes precipitation, and/or in an unstable region of asphaltenes deposition. Furthermore, the flocculating agent or flocculant may beneficially promote formation of larger clusters of asphaltenes within the production fluid, thus promoting more effective removal of the asphaltenes. Such may also promote flow assurance, as fewer asphaltenes particles will adhere to conduit walls because floc clusters are formed.

FIG. 7is an exemplary phase diagram700for asphaltenes in production fluid, depicting phases of asphaltenes as a function of pressure702and temperature704of the production fluid. The depicted pressure-temperature regions of the production fluid with asphaltenes indicates stability (or lack thereof) of the asphaltenes in the production fluid. In the illustrated example, the pressure702ranges linearly from about 300 pounds per square inch absolute (psia) (about 2,068 kilopascals (kPa)) to about 6,000 psia (about 41,369 kPa). In this example, the temperature704ranges linearly from about 80° F. (about 27° C.) to about 220° F. (about 93° C.). Of course, other pressure and temperature values and ranges may be considered.

Further, differing asphaltenes compositions may behave differently than depicted inFIG. 7. Indeed, the phase diagram700is only given as exemplary for discussion purposes of general concepts of asphaltenes phase behavior, and not intended to limit embodiments of the present techniques. Other asphaltenes phase diagrams, temperature ranges, pressure ranges, and so on, are applicable.

In the phase diagram700, an “unstable” region706represents conditions for the asphaltenes molecules precipitating from the production fluid. The “stable” regions710represent conditions for asphaltenes particles remaining dissolved or suspended in the production fluid. The “potentially unstable” regions708represent conditions at which asphaltenes molecules may begin to precipitate from the production fluid solution. The notation for the regions is given by a legend712of the exemplary phase diagram700.

Deposition of asphaltenes and associated fouling on equipment and piping is generally more likely to occur in the unstable region706and potentially unstable regions708, in comparison to a production fluid with asphaltenes operating in the stable region710. Evaluating asphaltenes stability can help to predict and avoid flow assurance issues. Production fluid in a reservoir at relatively high temperature and pressure upstream of a wellhead may typically be in the stable region710. As the production fluid passes through a wellhead from the reservoir, the production fluid may be subjected to a pressure drop and temperature drop across the wellhead that places the production fluid into unstable region706. In embodiments discussed herein, the flocculant addition and flocculating of asphaltenes may be implemented with the production fluid flowing in the stable region710and/or unstable region706. In examples, the asphaltenes react with the available flocculant while the production fluid is in the unstable region706.

While the present techniques may be susceptible to various modifications and alternative forms, the embodiments discussed above have been shown only by way of example. However, it should again be understood that the techniques are not intended to be limited to the particular embodiments disclosed herein. Indeed, the present techniques include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.