US 20030051874 A1
One configuration of a separation system for separating hydrocarbons from contaminants downhole includes a tubular membrane having a fluid inlet end and a fluid outlet end. Between the fluid inlet end and the fluid outlet end of the membrane tube the membrane material selectively permeates contaminants, such as carbon dioxide, through the membrane while preventing the hydrocarbon from passing through the membrane achieving the downhole separation. A driving force of the membrane is increased by passing a sweep gas past the output side of the membrane during membrane separation to remove or dilute the contaminant at the output side of the membrane. The sweep gas improves the driving force of the membrane by increasing a partial pressure difference across the membrane.
1. A system for separating a hydrocarbon and a contaminant in a wellbore, the system comprising:
a membrane for separating a hydrocarbon and a contaminant by passing the contaminant through the membrane from an input side to an output side of the membrane, the membrane configured to be positioned in the wellbore; and
a sweep fluid delivery system for delivering a sweep fluid to the output side of the membrane to improve a driving force driving the contaminant through the membrane.
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9. A method of separating a hydrocarbon and a contaminant in a wellbore, the method comprising:
separating a hydrocarbon and a contaminant in a wellbore with a membrane separator; and
delivering a sweep fluid to an output side of the membrane separator to improve a driving force driving the contaminant through the membrane.
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 The invention relates to recovery of hydrocarbons from a wellbore, and more particularly, the invention relates to technology for separation of contaminants from hydrocarbons in a wellbore with a membrane separation system using a sweep gas to enhance separation.
 Hydrocarbon gases and liquids are recovered from underground wellbores by drilling a wellbore into a hydrocarbon gas or liquid formation and withdrawing the materials under reservoir pressure or by artificial lifting. The fluids withdrawn from the reservoir consist of a combination of hydrocarbon liquids and gases, water, sediments, and other contaminants.
 The current recovery technology involves removing the hydrocarbon and any contaminants which are present from the wellbore, and separating the contaminants from the hydrocarbon above ground. This above ground separation is costly. Disposal of the removed contaminants may also present environmental problems. The contaminants which may be produced include carbon dioxide, nitrogen, water vapor, hydrogen sulfide, helium, other trace gases, water, water soluble organics, normally occurring radioactive material, and others.
 It would be highly desirable to selectively separate the contaminants in the wellbore for reinjection, removal, or other processing. One way to achieve downhole separation of contaminants from hydrocarbons is by the use of membranes.
 U.S. Pat. No. 6,015,011 describes a downhole hydrocarbon separator using membranes. The separator includes a permeable filter attached to the bottom of a packer so that a filter outlet end is in fluid communication with an aperture in the packer. The filter selectively passes fluids from beneath the packer to above the packer. However, the filter arrangement of U.S. Pat. No. 6,015,011 is inefficient in separating hydrocarbons from contaminants because of the arrangement of the membrane.
 In addition, International Patent Application No. WO 00/58603 describes a downhole hydrocarbon separator using tubular membranes for separation of hydrocarbons from contaminants. However, a gas membrane requires a partial pressure driving force across the membrane in order to drive the contaminants through the membrane. In this separator, a build up of the contaminants which have passed through the membrane will decrease the partial pressure driving force and decrease the efficiency of the separator.
 Current technology addresses this limitation of partial pressure driving force by running under conditions that allow for a significant quantity of product to permeate the membrane along with the contaminants. The product lost through the membrane serves to dilute the contaminant on the permeate side of the membrane and thereby help maintain a partial pressure driving force across the membrane. However, the product that permeates the membrane is then either lost or must be recovered in another manner. For example, the product methane that permeates the membrane is then recovered by recompressing the permeate and feeding the permeate to a second membrane stage, where some of the lost methane is recovered. This two stage approach has the drawback that interstage compression of the gas stream is required. Gas compressors are expensive in both capital and operating expense and require significant maintenance. Furthermore, gas compression cannot be conveniently accomplished downhole. Accordingly, it would be desirable to address the partial pressure driving force problem without allowing additional product to pass through the membrane.
 The present invention provides an efficient solution to downhole separation of hydrocarbons and contaminants. The system includes a membrane for separating hydrocarbons and contaminants and fluid sweep which dilutes removed contaminants and removes the contaminants from the vicinity of the membrane. The sweep fluid may be a gas with a low concentration of the removed contaminant or a liquid having a component which binds to or otherwise removes the contaminant from the location of the membrane.
 In accordance with one aspect of the present invention, a system for separating a hydrocarbon and a contaminant in a wellbore includes a membrane for separating a hydrocarbon and a contaminant by passing the contaminant through the membrane from an input side to an output side of the membrane and a sweep fluid delivery system for delivering a sweep fluid to the output side of the membrane to improve a driving force driving the contaminant through the membrane. The membrane for separating the hydrocarbon and contaminant is configured to be positioned in the wellbore.
 In accordance with another aspect of the present invention, a method of separating a hydrocarbon and a contaminant in a wellbore includes the steps of separating a hydrocarbon and a contaminant in a wellbore with a membrane separator, and delivering a sweep fluid to an output side of the membrane separator to improve a driving force driving the contaminant through the membrane.
 The invention will now be described in greater detail with reference to the preferred embodiments illustrated in the accompanying drawings, in which like elements bear like reference numerals, and wherein:
FIG. 1 is a schematic side cross sectional view of a downhole apparatus for separating hydrocarbons and contaminants having sweep gas according to a first embodiment;
FIG. 2 is a schematic side cross sectional view of a downhole apparatus for separating hydrocarbons and contaminants having a sweep gas according to an alternative embodiment;
FIG. 3 is a schematic side cross sectional view of a downhole apparatus for separating hydrocarbons and contaminants having a sweep gas according to another embodiment; and
FIG. 4 is a schematic side cross sectional view of a downhole apparatus for separating hydrocarbons and contaminants having a sweep gas according to a further embodiment.
 Downhole membrane separation systems are used for separating contaminants from hydrocarbon liquids and gases downhole. The contaminants which are removed downhole may be reinjected into an underground disposal formation or removed to the surface for disposal.
 One configuration of a downhole membrane separation system includes a tubular membrane having a fluid inlet end and a fluid outlet end. Between the fluid inlet end and the fluid outlet end of the membrane tube the membrane material selectively permeates one or more contaminant, such as carbon dioxide, through the membrane while preventing the hydrocarbon from passing through the membrane achieving the downhole separation.
 The passage of the contaminants through the membrane is controlled by the difference in partial pressures of the contaminants across the membrane. This partial pressure difference provides the driving force which drives the contaminants through the membrane. When the partial pressure difference becomes small, the removal of contaminates will slow and eventually stop.
 The partial pressure driving force is explained by the following example. In a hypothetical well, a product stream having a composition of 90% CH4 and 10% CO2 at a pressure of 1000 psia and a raffinate pressure held at 500 psia is delivered to the membrane separator. In this case, the partial pressure of the CH4 is 900 psia and the partial pressure of the CO2 is 100 psia. As the product stream enters the membrane separator, the partial pressure of the CO2 on the input or upstream side of the membrane is 100 psi and the partial pressure of the CO2 on the output or downstream side of the membrane is low, for example 5 psi. This results in a 95 psi partial pressure difference across the membrane which provides an adequate driving force for the membrane separator.
 However, as the product stream passes through the membrane separator towards an outlet end of the membrane separator, the concentration of the CO2 on the input side of the membrane decreases due to CO2 removal and the concentration of the CO2 on the output side of the membrane increases. This greatly decreases the partial pressure difference across the membrane reducing the driving force. For example, if the membrane is perfectly selective and permeates only CO2 and no methane, the permeate composition on the output side of the membrane will become 50 psia of CO2. Therefore, the product gas stream on the input side of the membrane can be purified to a limiting concentration of 50 psia partial pressure of CO2 or 5% CO2. In this example, the partial pressure driving force requirement limits the purity of the feed gas stream to 5% CO2 or greater.
 In known above-ground membrane systems, this partial pressure limitation is overcome by various process configurations, including, using higher pressure ratios, or using multiple stage membrane systems. Higher pressure ratios may require higher energy consumption to compress the feed, to recompress the permeate, or to generate a vacuum on the permeate side. Pressure ratio is also limited by the operational strength of the membrane materials. However, these methods are not feasible for downhole applications where pressure boosts or interstage compression are difficult.
 The present invention provides a downhole membrane separation system which improves the efficiency of separation by providing a sweep fluid to increase the driving force across the membrane. The sweep fluid diffuses, dilutes, reacts, absorbs or otherwise removes the separated contaminant from the output side of the membrane separator. Thus, the sweep fluid reduces the partial pressure of the contaminant on the output side of the membrane and increases the partial pressure difference across the membrane.
FIG. 1 illustrates a membrane separation system 10 for separating hydrocarbons from contaminants in a wellbore. The system 10 includes an outer perforated tube or casing 12 and an inner tube 14 positioned within the outer tube. A tubular membrane 16 forms a part of the inner tube 14 for separating hydrocarbons and contaminants. A first packer 18 and a second packer 20 provide a seal between the inner tube 14 and the outer tube 12 isolating a contaminant collection zone 22 from a production zone 26. As a produced stream including a hydrocarbon and one or more contaminants passes through the inner tube 14 from the production zone 26 to the surface, one or more contaminants permeates out though the membrane 16. The separated contaminants permeating out through the membrane 16 are collected in the contaminant collection zone 22. The collected contaminant in the contaminant collection zone 22 passes out of the outer tube 12 through perforations 28 into a disposal formation 30. Alternatively, the separated contaminants may be pumped or otherwise removed to the surface for disposal or further processing. The hydrocarbon plus any remaining contaminants that were not removed by the membrane 16 continue out an outlet end 34 of the inner tube 14 to the surface or to another separation system.
 The membrane separation system 10 also includes a sweep fluid delivery system for delivering a sweep fluid to an output or permeate side of the membrane 16. The sweep fluid is provided from a fluid source 36, through an optional heat exchanger 38, to a pump 40. The pump 40 pumps the sweep fluid in a liquid state into the wellbore through a delivery tube 42. The sweep fluid is flashed to a gas by a valve 44 located within the wellbore. The sweep gas then passes along an exterior or output side of the membrane 16 to increase the driving force of the membrane by reducing the partial pressure of the contaminant at the output side of the membrane.
 The sweep gas may be disposed of with the contaminants through the perforations 28 into the disposal formation 30. If necessary, the sweep gas can be used to increase the pressure of the fluid in the contaminant collection chamber 22 to a pressure which is sufficient to force the fluid from the contaminant collection chamber into the disposal formation 30. Alternatively, the sweep gas may be removed to the surface, separated from the contaminant, or reinjected into the production formation for pressurization.
 Examples of sweep gases which may be used to improve the operation of a contaminate removal membrane such as a carbon dioxide permeable membrane include water vapor, methanol, nitrogen, air, or noble gases. In addition, the sweep gas may be generated by flashing liquids to produce the desired gas stream. Preferably, the sweep gas is an inert gas that does not significantly permeate or harm the membrane material. The use of methanol as a sweep gas provides the added advantage of preventing hydrate formation within the wellbore which clogs up the pipes. The sweep gas can contain trace amounts of the contaminant, but should have a concentration such that the partial pressure of the contaminant in the contaminant collection zone 22 is less than a partial pressure of the contaminant in the production zone 26. Preferably, the delivered sweep gas contains less than 2% of the contaminant, and more preferably, less than 1%.
FIG. 2 illustrates an alternative embodiment of a separation system 50 in which a sweep gas is recovered to the surface with the contaminants and reused. The separation system 50 includes inner and outer tubes 12, 14 and a membrane 16 as in FIG. 1. The sweep fluid is delivered by the pump 40 through the delivery tube 42 to the expansion valve 44. The expanded sweep fluid is delivered uniformly around the membrane 16 by a manifold 52. The sweep gas passes along the exterior or output side of the membrane 16, removing the contaminant and/or diluting the contaminant concentration at the output side of the membrane. A contaminant removal pipe 54 is provided which extends through the upper packer 20 to remove the contaminant and sweep gas from the wellbore. The removed contaminant and sweep gas pass into a regenerator 56 which separates the contaminant for disposal, condenses the sweep gas, and delivers regenerated sweep fluid back to the source of sweep fluid 36.
 In the embodiments of FIGS. 1 and 2, the temperature and pressure of the liquid which is pumped by the pump 40 are carefully controlled to achieved the desired flash to liquid phase downhole by passing through the expansion valve 44.
 Although the embodiments of FIGS. 1 and 2 have been discussed above for use with a gas sweep, they may alternatively employ a liquid sweep fluid. The liquid sweep fluid is preferably a liquid in which CO2 or other contaminants dissolve or react. For example, sweep liquids for removal of CO2 include amines such as monoethanolamine, diethanolamine, and others. Examples of liquid sweep fluids preferably include water or another inexpensive liquid with a complexing agent added to remove the carbon dioxide. The complexing agent may be any of those agents which would be known to those skilled in the art, such as the complexing agents used in scrubbers. Examples of complexing agents include sodium hydroxide, magnesium hydroxide, other caustic agents, and amine.
 When a sweep liquid with a complexing agent is used, the expansion valve 44 is omitted and the sweep liquid is pumped into the wellbore to a location at the output side of the membrane 16. The sweep liquid reacts with, absorbs, adsorbs, or otherwise combines with the contaminant, such as carbon dioxide, to remove or dilute the contaminate.
 According to a further embodiment of the invention, the sweep fluid delivery system may be used to pump a sweep fluid downhole in a gaseous state as a sweep. Although gas is more expensive to pump than liquids, air or another gas sweep are advantageously inexpensive and useful as a sweep gas.
FIG. 3 illustrates an alternative embodiment of a membrane separation system 70 with a sweep fluid delivery and regeneration system. The embodiment of FIG. 3 takes advantage of the high temperatures deep within the wellbore to regenerate the sweep fluid. The system 70 of FIG. 3 includes an outer tube or casing 12, an inner tube or casing 14, and a tubular membrane 16.
 The sweep fluid delivery and regeneration system includes a pump 74 for delivering the sweep fluid through an injection tube 76 to the membrane 16. The sweep fluid delivered to the membrane 16 is preferably a liquid containing a complexing agent as described above. The liquid sweep fluid removes the separated contaminant from the contaminant collection zone 22 surrounding the membrane 16. The sweep fluid and contaminant enter a retrieval tube 78 and pass to a regenerator 82 where the fluids are expanded under carefully controlled conditions to cause the contaminant to flash to a gas while the liquid sweep fluid remains as a liquid. The regenerator 82 separates the contaminate from the sweep fluid by flashing and separating in a known manner. The regenerator 82 may be any of the known liquid/gas separators. The separated contaminant is delivered to the surface or to a disposal formation through an exhaust tube 84 and the sweep fluid is delivered by a tube 86 back to the pump 74 for reuse.
 The sweep fluid delivery and regeneration system of FIG. 3 takes advantage of the high temperature and low pressure present in the wellbore to separate the sweep fluid and the contaminant with the regenerator 82. In addition to performing sweep fluid regeneration downhole, as shown in FIG. 3, or on the surface, as shown in FIG. 2, the regeneration may be performed on a platform, on a ship, on the sea floor, or within a body of water.
FIG. 4 illustrates an alternative embodiment of a membrane separation system in which the sweep fluid is flashed and a gas component is used as a sweep gas or a liquid component is returned for reuse. A system 90 of FIG. 4 includes an outer tubular casing 12, an inner tubular casing 14, and a tubular membrane 16. The sweep gas is generated by heating water in the heat exchanger 38 and pumping the water with the pump 40 down to the underground expansion valve 44 where the heated water is flashed resulting in a gas stream and a liquid stream the gas and liquid streams are separated in a flash drum 92 and the liquid component is returned to the surface through the tube 94. The sweep gas component of the flashed water is fed by the tube 96 to the output side of the membrane. One example of a downhole membrane separation system with sweep gas as shown in FIG. 4, is described below.
 1,000,000 scfm of natural gas containing 10% CO2 is fed to a membrane system as shown in FIG. 4 at 1,000 psia. A sweep gas is generated by heating 20 gpm of water at 600 psi to temperature vary near the saturation temperature of 250° C. The heated sweep gas is pumped to the underground flash drum device 92 where heated water is flashed isenthalpically to a pressure of 40 psia resulting in a gas stream and a liquid stream at a lower temperature of about 131° C. Under these conditions about 25 weight percent of the feed water is converted to water vapor with the remaining 75% remaining liquid. The vapor and liquid are separated in the flash drum 92. The vapor portion is fed to the permeate side of the membrane 16 to serve as a sweep gas. 400,000 scfm of sweep gas at 40 psi is generated. The water is collected and pumped back to the heat exchanger 38.
 According to one example, a feed gas of 90% methane and 10% CO2 is fed to a CO2 selective membrane at a pressure of 1,000 psia and a flow rate of 1,000 scfm, with the raffinate pressure being held at 500 psia. We assume that the membrane is perfectly selective and permeates only CO2 and no methane. A countercurrent sweep of an inert gas, such as nitrogen at 500 psia and a flow rate of 400 scfm is introduced. CO2 can now be removed from the product gas down to a level of 2% CO2 content. This limit is a result of the overall mass balance and a limit on the driving force at the feed end of the membrane.
 Clearly, the product purity has improved from 5% CO2 without the sweep gas to 2% CO2 with the use of the sweep gas.
 FIGS. 1-4 each illustrate a single tubular membrane 16 for purposes of illustration. However, the membrane separation systems 10, 50, 70, and 90 may include multiple membranes arranged in series or parallel.
 The separation systems of the present invention have been illustrated in schematic form for ease of illustration. However, the separation systems may be incorporated in strings which may include one or more membranes, fluid directing elements, shear-out subs, fishing neck subs, seal assemblies, pack-off assemblies, and any other subs together in a configuration which is selected depending on the properties of a particular well. The assembled separation string may be lowered into a production tubing or may be assembled within a production tubing. The separation string is preferably deployable and retrievable with conventional deployment and retrieval tools.
 Although the separation system of the present invention has been illustrated for use in a vertical well it should be understood that the invention may be employed in horizontal wells and other non-vertical wells. The feed gas may be applied in a co-current, crossflow, or countercurrent fashion. The separation systems may be placed in a wellbore or on a subsea completion.
 Each of the membranes preferentially permeates one or more contaminant and excludes hydrocarbons. Although membrane materials are imperfect they can be used to greatly decrease the amount of contaminants which are brought to the surface and must be separated and disposed of by surface separation technology.
 The membranes may be stacked in different arrangements to remove contaminants from the flow of hydrocarbon in different orders depending on the application. The membranes may also be of a variable length depending on the particular application. The membranes may even be stacked to extend along the entire length of the wellbore for maximum contaminant removal.
 The number, type, and configuration of the membranes may vary depending on the particular well. The membranes may be of any known construction, such as hollow fiber or pleated. Pleated membranes may be used to increase surface area and improve performance. The separation system may be specifically designed for a particular well taking into account the type and amounts of hydrocarbon and contaminants present in the well, and the well configuration.
 Some of the contaminants which may be removed by the separation systems according to the present invention are gases including carbon dioxide, nitrogen, water vapor, hydrogen sulfide, helium, and other trace gases, and liquids including water, and other liquids. In addition, heavy hydrocarbons may be separated from hydrocarbon gases. When heavy hydrocarbons are separated from hydrocarbon gas, the heavy hydrocarbon is defined as the contaminant. However, the heavy hydrocarbon is preferably removed from the well for processing and use. The hydrocarbon from which the contaminants are separated according to the present invention may be oil, methane, ethane, propane, or others.
 The membranes according to the present invention are selected to be durable, resistant to high temperatures, and resistant to exposure to liquids. The materials may be coated or otherwise protected to help prevent fouling and improve durability. Examples of suitable membrane materials for removal of contaminants from a hydrocarbon gas stream include cellulose acetate, polysulfones, polyimides, cellulose triacetate (CTA), carbon molecular sieve membranes, ceramic and other inorganic membranes, composites comprising any of the above membrane materials with another polymer, composite polymer and molecular sieve membranes including polymer zeolite composite membranes, polytrimethylsilene (PTMSP), and rubbery polymers.
 Some examples of polyimides are the asymmetric aromatic polyimides in hollow fiber or flat sheet form. Patents describing these include U.S. Pat. No. 5,234,471 and U.S. Pat. No. 4,690,873.
 The present invention may be combined with existing downhole technologies for mechanical physical separation systems, such as cyclones or centrifugal separation systems. The invention may also be used for partial removal of the contaminants to reduce the burden on surface removal facilities with the remaining contaminants removed by conventional surface technologies. Some types of separated contaminants such as carbon dioxide can be reinjected into the productive horizon to maintain pressurization of the reservoir.
 While the invention has been described in detail with reference to the preferred embodiments thereof, it will be apparent to one skilled in the art that various changes and modifications can be made and equivalents employed, without departing from the present invention.