WO2021061780A1 - Stabilisateur de condensat modulaire compact - Google Patents

Stabilisateur de condensat modulaire compact Download PDF

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Publication number
WO2021061780A1
WO2021061780A1 PCT/US2020/052229 US2020052229W WO2021061780A1 WO 2021061780 A1 WO2021061780 A1 WO 2021061780A1 US 2020052229 W US2020052229 W US 2020052229W WO 2021061780 A1 WO2021061780 A1 WO 2021061780A1
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WO
WIPO (PCT)
Prior art keywords
vessel
hydrocarbon
stabilization apparatus
surface area
liquid
Prior art date
Application number
PCT/US2020/052229
Other languages
English (en)
Inventor
Diogo PIASSESKI
Prajakta SHRIRAO
Hamid HAJJOUBI
Original Assignee
Schlumberger Technology Corporation
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Technology B.V.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
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Application filed by Schlumberger Technology Corporation, Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Technology B.V. filed Critical Schlumberger Technology Corporation
Publication of WO2021061780A1 publication Critical patent/WO2021061780A1/fr

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Classifications

    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D3/00—Distillation or related exchange processes in which liquids are contacted with gaseous media, e.g. stripping
    • B01D3/34—Distillation or related exchange processes in which liquids are contacted with gaseous media, e.g. stripping with one or more auxiliary substances
    • B01D3/343—Distillation or related exchange processes in which liquids are contacted with gaseous media, e.g. stripping with one or more auxiliary substances the substance being a gas
    • B01D3/346—Distillation or related exchange processes in which liquids are contacted with gaseous media, e.g. stripping with one or more auxiliary substances the substance being a gas the gas being used for removing vapours, e.g. transport gas
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D3/00—Distillation or related exchange processes in which liquids are contacted with gaseous media, e.g. stripping
    • B01D3/42—Regulation; Control
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/003—Vibrating earth formations

Definitions

  • Embodiments herein generally relate to oil and gas drilling operations, and specifically to methods of containment at oil and gas drilling sites.
  • Stabilization systems are increasingly used at land-based sites to enable recovering hydrocarbons rather than venting or burning them. Stabilization typically means reducing the vapor pressure of a hydrocarbon mixture to a manageable level so that the hydrocarbon mixture can be handled — stored, transported, etc. — with minimal risk from evolution of hydrocarbon vapors. Stabilization systems typically include multiple pieces of equipment connected by piping, pumps, valves, and the like. Generally, these system are not designed for, and will not fit on, offshore production platforms because standard stabilization systems are large. Currently, pre-production hydrocarbons are typically burned at offshore sites. There is a need for stabilization systems that can be used on offshore drilling facilities.
  • Embodiments described herein provide a hydrocarbon stabilization apparatus, comprising a vessel; a heat source deployed inside the vessel; a fluid distribution manifold in a top portion of the vessel; a stripping fluid manifold in a bottom portion of the vessel; and a surface area structure located inside the vessel.
  • an offshore drilling apparatus comprising a drilling assembly; a production flow apparatus; and a hydrocarbon stabilization apparatus coupled to the production flow apparatus, the hydrocarbon stabilization apparatus comprising a vessel; a heat source deployed inside the vessel; a fluid distribution manifold in a top portion of the vessel; a stripping fluid manifold in a bottom portion of the vessel; and a surface area structure located inside the vessel.
  • a hydrocarbon stabilization method comprising flowing a produced hydrocarbon stream into a vessel containing a heating source deployed inside the vessel; providing a surface area structure inside the vessel; providing a heat supply using the heating source; removing a light hydrocarbon stream from an overhead location of the vessel; and removing a stabilized liquid hydrocarbon stream from a bottom location of the vessel.
  • Fig. 1 is a schematic cross-sectional view of a hydrocarbon stabilization apparatus according to one embodiment.
  • FIG. 2 is a schematic side view of an offshore drilling apparatus with hydrocarbon stabilization apparatus according to another embodiment.
  • FIG. 3 is a flow diagram summarizing a method according to one embodiment.
  • Fig. 4A is a schematic view of an upper portion of a hydrocarbon stabilization apparatus according to one embodiment.
  • FIG. 4B is a schematic view of an upper portion of a hydrocarbon stabilization apparatus 450 according to another embodiment.
  • Fig. 5A is a schematic isometric view of a surface area structure according to one embodiment.
  • Fig. 5B is a schematic isometric view of a surface area structure according to another embodiment.
  • Fig. 6 is a schematic view of a bottom portion of a hydrocarbon stabilization apparatus according to one embodiment.
  • FIG. 1 is a schematic cross-sectional view of a hydrocarbon stabilization apparatus 100 according to one embodiment.
  • the hydrocarbon stabilization apparatus 100 comprises a vessel 102 with a first end 103 and a second end 105 opposite from the first end 103.
  • a feed line 104 is located near the first end 103 of the vessel 102.
  • the feed line 104 is disposed through a sidewall 107 of the vessel 102, but the feed line 104 can be connected to the vessel 102 at any convenient location.
  • the feed line 104 is located such that the feed to the vessel is generally charged to a vapor area of the vessel 102, but the feed line 104 could be located to charge the feed to a liquid area of the vessel 102.
  • surge vessels are sometimes used for various applications. This vessel 102 can be a surge vessel for use on an offshore drilling platform.
  • the feed line 104 is fluidly coupled to a distributor 106.
  • the distributor 106 can be any convenient apparatus that can distribute a fluid flow across an area. Examples include showerheads, spargers, nozzles, and the like.
  • the distributor 106 is optional.
  • the feed line 104 may be used to charge the feed to the vessel 102 as a horizontal flow from the feed line 104 into the vapor area of the vessel 102, or the feed line may have a bend or corner to direct the fluid flow at least partially in a direction along a longitudinal axis of the vessel 102.
  • the feed here is typically a hydrocarbon mixture, potentially with other components commonly found in hydrocarbon reservoirs or produced with hydrocarbons from a reservoir.
  • the hydrocarbons commonly include liquids and gases ranging from methane (Ci) up through low vapor pressure hydrocarbon liquids such as oils, wax components, natural gasoline components, and the like.
  • the non hydrocarbon components of the feed typically include acid gases such as H2S and CO2, among others.
  • the high partial pressures of the light components of the feed make the feed unsuitable for storage in a vessel due to the hazard of developing very high pressures in the vessel.
  • Wellhead condensates are commonly encountered in well testing, and the apparatus 100 can be used to stabilize offshore condensates for storage or transportation.
  • the hydrocarbon stabilization apparatus 100 operates to remove high vapor pressure components from the feed stream to yield a hydrocarbon liquid stream suitable for storage in a vessel and/or transportation through a vessel or pipeline.
  • the feed exits the feed line 104 into the vapor area of the vessel 102 (or is injected into the liquid area of the vessel, as noted above), and begins to separate naturally as light components escape into the vapor phase.
  • the portion of the feed that does not separate ultimately flows down the vessel 102 and collects in a liquid area 114 in a bottom portion of the vessel 102. near the second end 105 thereof.
  • a heat source 108 is disposed inside the vessel 102 to be fully or partially immersed in the liquid collected in the liquid area 114.
  • the heat source 108 is typically an energy conduit of any convenient type that projects into the liquid collected in the liquid area 114 to deliver heat into the liquid. Heating the liquid vaporizes lighter components dissolved in the liquid, further lowering vapor pressure of the liquid.
  • a heat supply 112 is coupled to the heat source 108 to supply heat into the liquid.
  • the heat source 108 may be a fluid conduit, an electrical conduit, or a thermal conduit that does not involve material flow.
  • the heat source 108 is a steam coil
  • the heat supply 112 is a steam supply.
  • a steam system may provide pressurized steam as a utility for use in applying heat at various locations on the platform.
  • the heat source 108 is disposed through an opening 110, for example a personnel access portal (i.e. “manhole”) provided in the sidewall 107.
  • the personnel access portal is typically sealed and closed with a plate that is bolted to the portal.
  • the heat source 108 extends through the plate from a location outside the vessel 102 to a location in the interior of the vessel.
  • the heat source 108 may be articulated within the vessel 102, for example as shown here lengths of the heat source 108 may double back in multiple passes, to provide heat transfer capacity as needed for the heating duty of the heat source 108. A number of passes is shown here, and any number of passes can be used.
  • the heat source 108 shown here is sized for withdrawal through the opening 110 in one piece.
  • the heat source 108 could be larger than the opening 110 and could be inserted in pieces and constructed within the vessel 102, if desired.
  • the heat source 108 could be articulated to extend substantially across the vessel 102 from one side to, or near to, the other side thereof, and/or to extend substantially across the cross-sectional area of the vessel 102 adjacent to the sidewall 107 along the entire circumference thereof.
  • a support may be included along the sidewall 107, or extending from the second end 105, to provide support for the heat source 108.
  • Ascending vapor and descending feed contact and mix at one or more surface-area structures 116 provided inside the vessel between the first end 103 and the second end 105 in the vapor area of the vessel 102.
  • the surface-area structures are between the feed line 104 and the liquid area 114.
  • the surface-area structures are any structures that provide surface area for the feed liquid to spread to a large surface area for contact with the ascending vapor.
  • a packing in a support structure can be used as a surface-area structure. Trays of various description can also be used. Porous materials can also be used.
  • the apparatus 100 can be made more compact by choosing an optimum surface-area structure with very high surface area for contacting vapor and liquid.
  • Spherical balls in a support tray or box can be used in one example.
  • cylindrical packing elements, or irregularly shaped packing elements can be used.
  • the packing elements are typically secured between trays or mesh screens to immobilize the packing elements while allowing fluid flow through the packing structures.
  • packing structures When using packing structures, surface area, fluid flow rate, and pressure drop through the packing structure are typically optimized for the material flow duty and desired separation performance. Multiple packing structures can be used, as shown here where three packing structures are used. Alternately, the length of the packing structure can be increased to provide surface area with a desired porosity for fluid flow. So, one packing structure could be used, in place of the three shown in Fig. 1 , and the length of the packing structure can be somewhat arbitrarily extended to a location close to the liquid area 114.
  • the surface-area structures are made of materials resistant to process conditions inside the vessel 102.
  • the surface-area structures may be made of acid-resistant materials where substantial quantities of acid gases are encountered.
  • the surface-area structures are also typically made of materials resistant to the elevated temperatures that develop inside the vessel 102. Such materials can include ceramic materials, alloy materials, glass, and high-density acid- resistant plastics.
  • the vapor line 118 exits from the top of the vessel 102, but the vapor line can exit from any convenient location, even between the surface-area structures 116 and the liquid area 114 in some cases.
  • Stabilized liquid exits the vessel 102 through a liquid line 120 disposed near the second end 105 of the vessel 102 in fluid communication with the liquid area 114.
  • the liquid line 120 may include a projection 122 that extends into the vessel 102 away from the second end 105 into the liquid area 114. The projection 122 can prevent water from exiting with hydrocarbon liquids through the liquid line 120.
  • a drain (not shown) can be provided at a low point of the vessel 102 to drain any produced water that enters the vessel 102.
  • the liquid from the hydrocarbon stabilization apparatus 100 is routed to a cooler to prepare the liquid for storage at an appropriate temperature. In some cases, the liquid from the hydrocarbon stabilizer can be used to preheat the feed in order to recover heat input by the heat source.
  • a liquid control valve 124 can be coupled to the liquid line 120 to control liquid output from the vessel 102. The liquid control valve 124 can be used to control liquid level in the vessel 102, for example if a level instrument or other level indication is available.
  • a controller such as a digital processor, can control the liquid level in such cases.
  • a vapor control valve 126 can be coupled to the vapor line 118 to control vapor output flow from the vessel 102.
  • Stabilization efficiency can be increased, and vessel 102 compactness optimized, by increasing heat input to the vessel 102 and by improving contact between vapor and liquid in the vessel.
  • vapor-liquid contact will naturally decline due to liquid and gas channeling through the surface-area structures.
  • Use of tray structures can reduce such tendency, potentially with the cost of lower overall vapor-liquid contact.
  • channeling can be reduced by using flow distributors.
  • a flow distributor 124 is shown here between the feed line 104 and the surface-area structures 116.
  • the flow distributor 124 is a perforated plate in this case, but any convenient structure can be used as a flow distributor.
  • the feed is dispensed from the feed line 104 onto the flow distributor 124.
  • flow distributors can be provided between the sections to further reduce channeling tendencies through the structures.
  • Fig. 2 is a schematic elevation view of a drilling apparatus 200 according to another embodiment.
  • the drilling apparatus 200 which is not intended to illustrate any particular kind of drilling apparatus, includes a drilling assembly 210, a production flow apparatus 212, and a plurality of the hydrocarbon stabilization apparatus 100.
  • Each hydrocarbon stabilization apparatus 100 is housed in a frame 202 that permits the hydrocarbon stabilization apparatus 100 to be shipped and deployed at a desired location on the drilling apparatus 200.
  • two hydrocarbon stabilization apparatus 100 are shown located adjacent to the drill floor, with a storage vessel 204 fluidly coupled to the hydrocarbon stabilization apparatus 100.
  • the liquid outlet of each hydrocarbon stabilizer 100 is fluidly coupled to an inlet of the storage vessel 204.
  • each hydrocarbon stabilizer 100 is fluidly coupled to a flare utility 206 of the apparatus 200.
  • a third hydrocarbon stabilizer 100 is shown located on an upper deck 208 of the apparatus 200. In some cases, the stabilizers 100 can even be stacked directly, one on another, by bolting the frames 202 together. In the elevation view of Fig. 2, other equipment that may be included on the apparatus 200 is omitted for clarity
  • Fig. 3 is a flow diagram summarizing a method 300 according to another embodiment.
  • the method 300 can be practiced using the hydrocarbon stabilization apparatus 100 in any context, such as the context of the drilling apparatus 200 of Fig. 2.
  • a produced hydrocarbon stream is routed to a vessel containing a heat source.
  • the vessel may be the vessel 102 of the apparatus 100, and the heat source may be a heating coil such as a steam coil.
  • the vessel will contain a surface-area structure to provide a large interface surface area for vapor- liquid contact inside the vessel.
  • a heat supply is provided using the heat source to vaporize a portion of the feed that falls to the bottom of the vessel.
  • the vaporization takes place right in the vessel, reducing the vapor pressure of the liquid in the vessel.
  • Light hydrocarbons are recovered from an overhead location of the vessel at 306, and liquid hydrocarbons are recovered from a bottom location of the vessel. The liquid hydrocarbons are stabilized by removal of light components.
  • the liquid hydrocarbons recovered from the bottom location of the vessel are cooled to a threshold temperature.
  • the heat supply may be controlled by measuring temperature of the liquid in the vessel.
  • the liquid will reach a temperature that is a bubble point that volatilizes an increment of material based on vessel pressure and liquid and gas composition.
  • concentration of light material in the liquid increases, temperature of the liquid may decrease as the bubble point of the liquid decreases.
  • the heat supply may be increased to increase vaporization of light hydrocarbons from the liquid, thus returning the composition to a higher bubble point and restoring the temperature of the liquid.
  • the temperature of the liquid grows heavier, the temperature of the liquid will rise and heat input can be decreased to rectify the composition of the liquid.
  • the stabilizers can be used in series or in parallel.
  • the stabilizers can be flexibly manifolded to allow series or parallel operation.
  • Series operation can be beneficial when composition of the feed is broad, with substantial quantities of high vapor pressure components.
  • a first hydrocarbon stabilizer can be operated at a first pressure
  • the liquid from the first hydrocarbon stabilizer can be provided to a second hydrocarbon stabilizer
  • the second hydrocarbon stabilizer can be operated at a second pressure less than the first pressure.
  • the step-down in pressure allows removal of lighter components using two removal apparatus to avoid overwhelming the gas exit lines, and also reduces temperature of the liquid exiting the second stabilizer.
  • FIG. 4A is a schematic view of an upper portion of a hydrocarbon stabilization apparatus 400 according to one embodiment.
  • a vessel 402 has a distribution manifold 404 for distributing a hydrocarbon mixture into the vessel 402.
  • the distribution manifold 404 includes a feed line 406 that enters through a wall 408 of the vessel 402.
  • the feed line 406 extends to a central area 410 of the vessel 402, for example near a cylindrical axis of the vessel 402, and couples to a plurality of branch lines 412 that extend radially outward from the central area 410.
  • Each branch line has an angled connector 413 that connects to a nozzle 414.
  • the nozzle 414 is generally cylindrical and hollow with a plurality of longitudinal slots 416 for flowing a fluid out of the nozzle 414.
  • the nozzles 414 are oriented in a direction substantially parallel with a longitudinal axis 416 of the vessel 402. In Fig. 4A, the nozzles are all located along a circular path around the central area 410 at a constant radial distance from the center of the vessel 402.
  • Hydrocarbon fluid flows through the feed line 406 to the branch lines 412 and out to the fingers 412 and the nozzles 414.
  • the hydrocarbon fluid enters the interior of the hollow nozzles 414 and exits through the slots 416 into the interior of the vessel 402.
  • the vessel 402 has a distribution tray 420 located adjacent to the nozzles 414.
  • the nozzles 414 may be in direct contact with the distribution tray 420 or spaced apart from the distribution tray 420 by a small distance. Hydrocarbon fluid exiting the nozzles 414 drops onto the tray 420 and collects on the tray 420.
  • the tray 420 has a plurality of openings 422 that allow fluid to pass through. Liquid falls through the openings 422 and vapor rises through the openings 422.
  • the distribution manifold 404, and its proximity to the distribution tray 420 efficiently distributes the hydrocarbon fluid onto the distribution tray 420, promoting mixing along the tray 420 and avoiding large flow disruptions and spillover that can reduce thermodynamic efficiency of the stabilization apparatus 400.
  • the distribution tray 420 may have a small raised rim to direct all the fluid through the holes in the distribution tray 420.
  • the nozzles 414 of Fig. 4A are all spaced apart from the central area 410 by a radial distance that is the same. In other embodiments, the nozzles 414 may be spaced apart from the central area 410 by different radial distances.
  • the nozzles 414 of Fig. 4A are all an equal distance from the tray 420, which may be zero as described above. In other embodiment, the nozzles 414 may be spaced apart from the tray 420 by different distances.
  • FIG. 4B is a schematic view of an upper portion of a hydrocarbon stabilization apparatus 450 according to another embodiment.
  • This version has a distribution manifold 452 with two sets of branch lines 412.
  • An extension 454 extends vertically from the end of the feed line 406, in this case downward, near the central area 410.
  • a first plurality of branch lines 412 extends from a lower portion of the riser 454, each branch line 412 of the first plurality extending a first radial distance from the central area 410.
  • a second plurality of branch lines 412 extends from an upper portion of the riser 454, each branch line 412 of the second plurality extending a second radial distance from the central area 410.
  • the first radial distance is greater than the second radial distance.
  • Each branch line 412 of the first and second pluralities of branch lines 412 connects to a nozzle 414, as described above in connection with Fig. 4A.
  • the nozzles 414 are spaced apart from the tray 420 by different distances.
  • a first plurality of nozzles 414 coupled to the first plurality of branch lines 412 is spaced apart from the tray 420 by a first distance, which can be zero (i.e.
  • the first plurality of nozzles can be in direct contact with the tray 420), while a second plurality of nozzles 414 coupled to the second plurality of branch lines 412 is spaced apart from the tray 420 by a second distance greater than the first distance.
  • a distribution manifold such as the distribution manifold 452 of Fig. 4B provides the flexibility to have more nozzles 414 without disrupting the radial path of the branch lines 412. In particular, more nozzles 414 can be provided near the central area 410, if that is desired.
  • Such distribution manifolds can increase dispersion and distribution of fluid on the tray 420 while keeping flow disruption along the tray 420 to a minimum.
  • a pressure reduction manifold 430 is coupled to the hydrocarbon stabilization apparatus 400.
  • the pressure reduction manifold 430 is optional, and may be used with any of the embodiments shown and described herein.
  • An effluent line 432 is coupled to the vessel 402 to facilitate material flow out of the vessel 402. Although not specifically shown in each figure, every embodiment described herein has an effluent line for material removal. In Fig. 4A, the effluent line 432 is coupled to an overhead portion 434 of the vessel 402. An ejection line 436 is coupled to the effluent line 432.
  • An ejection gas flows through the ejection line 436, resulting in reduced pressure in the effluent line 432, and in the vessel 402.
  • An orifice feature 438 can be used in the ejection line 436 to control pressure in the vessel 402.
  • the orifice feature 438 may be a simple orifice or a valve of any suitable type.
  • An orifice feature (not shown) may also be used in the effluent line 432. If more pressure reduction is desired, the effluent line 432 may be connected to a vacuum pump (not shown), or the ejection line 436, into which the effluent line 432 joins, can be coupled to a vacuum pump.
  • a surface area structure for use herein will have a plurality of components.
  • Figs. 5A and 5B are two types of surface area structures that can be used, for example as any of the surface area structures 116 of Fig. 1 .
  • Fig. 5A is a schematic isometric view of a surface area structure 500 according to one embodiment.
  • the surface area structure 500 consists of a plurality of plates 502 stacked together. Each plate 502 has a plurality of holes 504 for fluid transmission through the plate 502.
  • the plates 502 may be rotated with respect to neighboring plates to provide a tortuous path for fluid flow through the surface area structure 500.
  • Each plate 502 may be rotated a set amount with respect to a neighboring plate 502, such that the openings of the plates 502 are distributed with uniform azimuth, or the plates 502 may be rotated a random or patterned amount.
  • the holes 504 are only visible in the top plate 502, the holes of the other plates 502 being obscured by proximity of each plate 502 to neighboring plates 502.
  • the plates 502 may be in direct contact, such that one plate 502 is in direct contact with two neighboring plates 502. Alternately, the plates 502 may be spaced apart.
  • spacing between the plates 502 may be more or less than thickness of the plates 502.
  • plates having thickness of 2-3 mm may be spaced apart from 2 to 5 mm.
  • a stack of plates 502, as a surface area structure, may be from 0.5 m to 1 .0 m thick.
  • Fig. 5B is a schematic isometric view of a surface area structure 550 according to another embodiment.
  • the structure 550 is similar to the structure 500 in that the structure 550 comprises a plurality of the plates 502, each having the holes 504. In this case, however, the plates 502 are separated by a layer of structured packing material 552. In this case, each pair of neighboring plates 502 in the surface area structure 550 is separated by a layer of structured packing material 552.
  • the structured packing material 552 may be any high surface area structure, such as a collection of balls or other shaped objects.
  • each layer of structured packing material 552 is shown having the same thickness, but each layer 552 could have different thickness, according to the needs of a particular process. Similar to the surface area structure 500 of Fig.
  • the porosity and/or surface area of the surface area structure 550 is also adjustable by changing the relative orientation of the plates 502, but the structure 550 has a higher minimum porosity and surface area than a similar structure with no structured packing material, and a lower range of selectable porosity, than the structure 500.
  • such surface area structures can be used as the surface area structures 116 of Fig. 1.
  • the structure 550 shown in Fig. 5B features a layer of structured packing material between each neighboring pair of plates.
  • Other embodiments may use fewer layers of structured packing material.
  • a single layer of structured packing material might separate two sections of stacked plates like the structure 500.
  • a first number of structured packing material sections in the structure 550 might be different from a second number of plates having holes.
  • the first number might be a fraction of the second number, such as one-half or two-thirds.
  • the ratio of structured packing materials to rotatable plates having holes influences the scalability of porosity of the structure 550, with more structured packing increasing overall surface area but decreasing porosity scalability and less structured packing reducing overall surface area.
  • the plates 502 can be any thickness, but using thin plates allows for stacking more plates to provide more surface area. In one case, the plates 502 have thickness of 2-3 mm
  • Fig. 6 is a schematic view of a bottom portion of a hydrocarbon stabilization apparatus 600 according to one embodiment.
  • the stabilization apparatus 600 features equipment that is usable with any embodiment described herein.
  • the equipment in the bottom portion of the apparatus 600 improves stabilization efficiency by providing thermal energy to vaporize volatile species.
  • a heat source 608 is disposed in an interior of a vessel 602 to supply thermal energy to the fluid in the vessel 602.
  • the heat source 608 may be a conduit for a hot fluid, such as steam or hot oil or water, to pass through the fluid in the vessel 602 to transfer thermal energy to the fluid in the vessel 602.
  • the heat source 608 may be electrical, for example using resistive heating to transfer thermal energy to the fluid in the apparatus 600.
  • the heat source 608 may have a combination of heating methods.
  • the stabilization apparatus 600 includes a stripping fluid manifold 610 that dispenses a stripping fluid into the vessel 602.
  • the stripping fluid manifold 610 has a branch line structure similar to the fluid distribution manifold described above in connection with Figs. 4A and 4B.
  • the stabilization apparatus 600 is typically operated such that the stripping fluid manifold 610 is submerged in a hydrocarbon, or majority hydrocarbon, liquid. Stripping fluid is provided through the stripping fluid manifold 610 to nozzles 612, which may be the same as the nozzles 414 of Figs. 4A and 4B.
  • the stripping fluid is typically a gas, and may be any inert gas such as nitrogen, steam, hydrogen, or another gas that does not react with the fluid being stabilized in the apparatus 600, or with the materials of the apparatus 600.
  • the stripping fluid is bubbled through the liquid phase in the vessel 602 to enhance evaporation of volatile species.
  • the bubbling action of the stripping fluid also accelerates separation of components vaporized by addition of thermal energy using the heat source 608 by providing upward momentum that moves vapor species toward the vapor phase in the vessel 602 with increased velocity.
  • the stripping fluid manifold 610 is disposed in the vessel 602 to allow the stripping fluid to percolate toward and past the heat source 608.
  • the stripping fluid manifold 610 may be located between the heat source 608 and a liquid end of the vessel 602. The stripping fluid moving past the heat source 608 moves vaporized species upward through the fluid column to accelerate separation thereof.
  • a distribution tray like the tray 420 of Figs. 4A and 4B may be used with the stripping fluid manifold 610.
  • the tray may be located between the stripping fluid manifold 610 and the heat source 608, or the stripping fluid manifold 610 and the heat source 608 may be located on the same side of the tray, with the tray located between the heat source 608 and the upper portion of the apparatus 600 (not shown).
  • the stripping fluid manifold 610 may include a heater 612 to provide thermal energy to the stripping fluid entering the vessel.
  • the heater may be a furnace heater, a heat jacket, or other apparatus for heating a gas flowing through a line.
  • Heating the stripping fluid adds additional thermal energy to the hydrocarbon fluid beyond that added by the heat source in the vessel, and can improve removal of light hydrocarbons.
  • the hydrocarbon stabilization apparatus described herein generally have effluent lines located in lower and upper portions of the apparatus to withdraw liquid and vapor species after stabilization.
  • the vapor effluent is located above the distribution tray 420, for example at a vapor end of the treatment vessel, and the liquid effluent is located in a liquid portion of the apparatus, which may be below one or both of the heat source 608 and the stripping fluid manifold 610, for example at the liquid end of the treatment vessel.
  • the apparatus embodiments described above can be used to stabilize hydrocarbon materials by flowing a hydrocarbon stream, for example a hydrocarbon stream produced from a wellhead, into a vessel containing a heating source deployed inside the vessel, providing a surface area structure inside the vessel, providing a heat supply using the heating source, removing a light hydrocarbon stream from an overhead location of the vessel, and removing a stabilized liquid hydrocarbon stream from a bottom location of the vessel.
  • a hydrocarbon stream for example a hydrocarbon stream produced from a wellhead
  • the hydrocarbon stream is provided to the vessel at a feed point using a distribution manifold that deposits the hydrocarbon stream through nozzles located near a distribution tray to minimize or reduce turbulence in the fluid on the distribution tray.
  • the fluid contacts rising vapor on the distribution tray, and liquid components of the fluid decline through holes in the distribution tray.
  • the heat source is a device that supplies thermal energy into the liquid pool from outside the vessel, for example a conduit for a hot fluid, such as steam, or a resistive heating coil.
  • the thermal energy vaporizes or volatilizes light components of the hydrocarbon in the liquid pool, which rise toward the upper portion of the vessel.
  • a stripping fluid can be applied to the liquid pool using a stripping fluid distribution manifold immersed in the liquid pool.
  • the stripping fluid may be an inert gas, such as nitrogen, steam, or hydrogen, and may be bubbled into the liquid pool below the heat source.
  • the percolating stripping fluid encourages and accelerates separation of vapor species from the liquid pool into the vapor phase.
  • the surface area structure is located between the feed point and the heat source, and may include a plurality of perforated plates stacked together to provide a tortuous path for liquid and gas flow through the surface area structure.
  • the surface area structure also provides a large contact area for the vapor and liquid phases to maximize thermodynamic efficiency.

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  • Geochemistry & Mineralogy (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

La présente invention concerne un appareil de stabilisation d'hydrocarbures. L'appareil de stabilisation d'hydrocarbures comprend un récipient, une source de chaleur déployée à l'intérieur du récipient, et une structure de zone de surface située à l'intérieur du récipient. La structure de zone de surface peut être une pluralité de plaques perforées qui sont empilées ensemble. La source de chaleur peut être un serpentin à vapeur ou un autre dispositif d'entrée de chaleur. Un tel appareil de stabilisation d'hydrocarbures peut être déployé sur un appareil de forage en mer pour récupérer des hydrocarbures produits pendant un test et une évaluation de pré-production.
PCT/US2020/052229 2019-09-23 2020-09-23 Stabilisateur de condensat modulaire compact WO2021061780A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201962904457P 2019-09-23 2019-09-23
US62/904,457 2019-09-23

Publications (1)

Publication Number Publication Date
WO2021061780A1 true WO2021061780A1 (fr) 2021-04-01

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Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3437564A (en) * 1966-03-21 1969-04-08 Phillips Petroleum Co Purification of cyclohexane by fractional distillation with bottoms stream heat exchange
RU2268840C2 (ru) * 2003-09-01 2006-01-27 Николай Васильевич Кореков Морской автономный комплекс (мак)
US20150073195A1 (en) * 2013-09-11 2015-03-12 Ortloff Engineers, Ltd. Hydrocarbon Processing
EP3037149A1 (fr) * 2014-12-23 2016-06-29 Sulzer Chemtech AG Plateau de contact de fluide, en particulier pour l'utilisation dans une colonne de fractionnement en mer

Patent Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3437564A (en) * 1966-03-21 1969-04-08 Phillips Petroleum Co Purification of cyclohexane by fractional distillation with bottoms stream heat exchange
RU2268840C2 (ru) * 2003-09-01 2006-01-27 Николай Васильевич Кореков Морской автономный комплекс (мак)
US20150073195A1 (en) * 2013-09-11 2015-03-12 Ortloff Engineers, Ltd. Hydrocarbon Processing
EP3037149A1 (fr) * 2014-12-23 2016-06-29 Sulzer Chemtech AG Plateau de contact de fluide, en particulier pour l'utilisation dans une colonne de fractionnement en mer

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