Heat recovery from condensed steam in gas-oil separation plant to heat crude oil

Abstract

Methods and systems are disclosed. Systems may include a crude oil feed, steam recovery system, and first heat exchanger. The crude oil feed may be configured to receive a flow of crude oil. The steam recovery system may be configured to receive a first flow of low-pressure steam and produce a first flow of condensed steam. The first heat exchanger may be disposed along the crude oil feed. The first heat exchanger may be configured to receive the flow of crude oil and the first flow of condensed steam and produce, using the first flow of condensed steam, a first flow of treated crude oil from the flow of crude oil.

Description

BACKGROUND

[0001] In the upstream oil and gas industry, a gas-oil separation plant (GOSP) is configured to separate gas and liquid components from wild raw crude oil using distillation. The wild raw crude oil may flow from a reservoir below ground through a well and into a pipeline above ground that transports the wild raw crude oil to the GOSP.

[0002] At the GOSP, various forms of energy are used to help separate the gas and liquid components from the wild raw crude oil to produce stable crude oil. Some energy may be transferred to the GOSP from external facilities while excess residual energy produced at the GOSP as a byproduct of separating the wild raw crude oil may be transferred to external facilities once cooled.SUMMARY

[0003] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0004] In general, in one aspect, embodiments relate to a system. The system includes a crude oil feed, steam recovery system, and first heat exchanger. The crude oil feed is configured to receive a flow of crude oil. The steam recovery system is configured to receive a first flow of low-pressure steam and produce a first flow of condensed steam. The first heat exchanger is disposed along the crude oil feed. The first heat exchanger is configured to receive the flow of crude oil and the first flow of condensed steam and produce, using the first flow of condensed steam, a first flow of treated crude oil from the flow of crude oil.

[0005] In general, in one aspect, embodiments relate to a method. The method includes receiving, in a crude oil feed, a flow of crude oil and receiving, by a steam recovery system, a first flow of low-pressure steam. The method further includes producing, from the steam recovery system, a first flow of condensed steam from the first flow of low-pressure steam and receiving, by a first heat exchanger, the flow of crude oil and the first flow of condensed steam. The method still further includes producing, from the first heat exchanger using the first flow of condensed steam, a first flow of treated crude oil from the flow of crude oil.

[0006] Any combinations of the various embodiments and implementations disclosed herein can be used in a further embodiment, consistent with the disclosure. Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.BRIEF DESCRIPTION OF DRAWINGS

[0007] FIG. 1 shows a flowchart of GOSP-related systems in accordance with one or more embodiments.

[0008] FIG. 2 shows a flowchart of conventional GOSP operations in accordance with one or more embodiments.

[0009] FIG. 3 shows a projection of low-pressure steam demand in accordance with one or more embodiments.

[0010] FIGS. 4-6 show a flowchart of disclosed systems in accordance with one or more embodiments.

[0011] FIG. 7 shows a method in accordance with one or more embodiments.DETAILED DESCRIPTION

[0012] In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

[0013] Throughout the application, ordinal numbers (for example, first, second, third) may be used as an adjective for an element (that is, any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.

[0014] It is to be understood that the singular forms “a,”“an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to “a fluid sample” includes reference to one or more of such samples.

[0015] Terms such as “approximately,”“substantially,” etc., mean that the recited characteristic, parameter, or value need not be achieved exactly, but that deviations or variations, including for example, tolerances, measurement error, measurement accuracy limitations and other factors known to those of skill in the art, may occur in amounts that do not preclude the effect the characteristic was intended to provide.

[0016] It is to be understood that one or more of the steps shown in the flowcharts may be omitted, repeated, and / or performed in a different order than the order shown. Accordingly, the scope of the invention should not be considered limited to the specific arrangement of steps shown in the flowcharts.

[0017] Although multiple dependent claims are not introduced, it would be apparent to one of ordinary skill that the subject matter of the dependent claims of one or more embodiments may be combined with other dependent claims.

[0018] Embodiments disclosed herein relate to a system and methods of using the same. In some embodiments, the system may be included, in part, within a gas-oil separation plant (GOSP). The GOSP may be configured to separate gas and liquid components from raw crude oil using various forms of energy thereby purifying the raw crude oil. The purification process may be referred to as distillation.

[0019] Systems that may be used in a conventional GOSP are shown in FIG. 1. Specifically, FIG. 1 shows a flowchart of the systems in accordance with one or more embodiments. Note the systems described below are for illustration purposes only and are not intended to limit the scope of the disclosure.

[0020] Upstream of the GOSP, a flow of crude oil 100a may be extracted from a hydrocarbon reservoir located below ground using a well. Though the generic term “flow of crude oil” is primarily used throughout the disclosure, the flow of crude oil 100a may be a flow of wet crude oil. Wet crude oil is defined as untreated crude oil that contains water, gas, and sediment. Further, wet crude oil may be synonymous to “wild crude oil,”“raw crude oil,” or “wild raw crude oil.” Above ground, the flow of crude oil 100a may flow through one or more crude oil feeds (e.g., pipelines) towards the GOSP. On the way, the flow of crude oil 100a may be split such that a portion of the flow of crude oil 100a reaches each of multiple GOSPs. In other words, multiple GOSPs may be configured to separate a first flow of gas 105a and flow of liquid 110 from the flow of crude oil 100a. In some embodiments, a central processing facility (CPF) may include the multiple GOSPs operating in series and / or parallel. In these embodiments, the CPF may receive hundreds of thousands of barrels of crude oil per day. Further, in these embodiments, each GOSP may receive a flow of crude oil 100a with common gas compression, dehydration, and dew point control.

[0021] Keeping with FIG. 1, at the GOSP, the flow of crude oil 100a may flow to and be received by an inlet facility 115. The inlet facility 115 may be configured to largely—though maybe not completely—separate the first flow of gas 105a and flow of liquid 110 from the flow of crude oil 100a. Accordingly, each of the flow of crude oil 100a, first flow of gas 105a, and flow of liquid 110 may contain impurities and / or other types of flows. For example, the flow of liquid 110 may include a mixture of water and crude oil.

[0022] The inlet facility 115 may include separators such as, without limitation, production traps, heat exchangers, and low-pressure degassing tanks (LPDT). In some embodiments, the production trap may include a high-pressure production trap (HPPT), low-pressure production trap (LPPT), or combination thereof. The pressure of a combined HPPT and LPPT may depend on the arrival of the pressure and amount of gas in the flow of crude oil 100a. The heat exchanger may include a trim heat exchanger, wet and dry (W / D) heat exchanger, flash drum heat exchanger, condensed steam heat exchanger, or combination thereof. In some embodiments, a trim heat exchanger may include a shell and tube and be configured to heat, using a flow of LP steam, a flow of crude oil 100a. In some embodiments, a wet and dry (W / D) heat exchanger may include a shell and tube and be configured to heat, using a flow of dry crude oil, a flow of crude oil 100a after the flow of crude oil 100a passes through a production trap. Dry crude oil may be defined as crude oil with negligible amounts of water, gas, and / or sediment. Hereinafter the generic term “heat exchanger” may be used to describe any type of heat exchanger. Each separator in the inlet facility 115 may be a two-phase separator to separate the first flow of gas 105a from the flow of crude oil 100a or a three-phase separator to separate the first flow of gas 105a and flow of liquid 110 from the flow of crude oil 100a. Note the process of separating a flow of liquid 110 that contains water from a flow of crude oil 100a is known as dewatering.

[0023] The first flow of gas 105a may flow to and be received by a gas compression system 120. The gas compression system 120 may be configured to compress the first flow of gas 105a to produce a flow of compressed gas 105b, first flow of condensate 125a (e.g., non-water liquid), and first flow of water 130a. To do so, the gas compression system 120 may include, without limitation, gas compressors, heat exchangers, knockout drums, and cooling mechanisms.

[0024] The flow of compressed gas 105b may flow to and be received by a gas treatment system 135. The gas treatment system 135 may be configured to reduce impurities in the flow of compressed gas 105b to produce a flow of treated gas 105c and second flow of condensate 125b. Impurities may include hydrogen sulfide and carbon dioxide (CO2). The gas treatment system 135 may rely on mechanical and / or chemical means to reduce impurities.

[0025] The flow of treated gas 105c may then flow to and be received by a pipeline compression system 140. The pipeline compression system 140 may be configured to further compress the flow of treated gas 105c. The flow of treated compressed gas 105d may then flow to and be received by a dry gas downstream facility 145 outside the GOSP.

[0026] The flows of condensate 125a, b produced at the gas compression system 120 and / or gas treatment system 135 may flow to and be received by the condensate storage and export facility 150. The flows of condensate 125a, b may include hydrocarbon condensate and / or water condensate. The condensate storage and export facility 150 may be configured to prepare the flows of condensate 125a, b to be sent to and received by a condensate downstream facility 155 outside the GOSP.

[0027] Returning to the first flow of water 130a produced at the gas compression system 120, the first flow of water 130a may include hydrocarbons. As such, the first flow of water 130a may flow to and be received by a crude handling system 160 configured to extract the hydrocarbons from the first flow of water 130a.

[0028] Returning to the flow of crude oil 100a produced at the inlet facility 115, the flow of crude oil 100a may flow to and be received by the crude handling system 160. The crude handling system 160 may be configured to separate the flow of crude oil 100a into a flow of crude oil 100a and second flow of water 130b. To do so, the crude handling system 160 may include separators such as, without limitation, desalting systems, gas removal systems, heat exchangers, dehydrators, water knockout drums, and settling tanks. Desalting may be performed by extracting the second flow of water 130b, which may include salt, from the flow of crude oil 100a. Examples of desalting systems include first stage desalters and second stage desalters. The heat exchanger may include a flash drum. The flash drum may include a shell and tube and be configured to heat a flow of dry crude output from a second stage desalter using a flow of LP steam.

[0029] The flow of crude oil 100a produced at the crude handling system 160 may flow to and be received by a crude stabilization system 165. The crude stabilization system 165 may be configured to largely separate volatile components from the flow of crude oil 100a to produce a flow of crude oil 100a and second flow of gas 105e. Volatile components may include light hydrocarbons such as, without limitation, methane, ethane, propane, and butane. To separate volatile components, the crude stabilization system 165 may include separators such as, without limitation, stabilizer columns, stabilizer towers, stripping columns, and heat exchangers. The stripping columns may strip dissolved gases (e.g., natural gas) from the flow of crude oil 100a.

[0030] The second flow of gas 105e may flow to and be received by the gas treatment system 135.

[0031] The flow of crude oil 100a may flow to and be received by the crude storage and export facility 170. The crude storage and export facility 170 may be configured to prepare the flow of crude oil 100a to be sent to and received by a crude downstream facility 175 outside the GOSP.

[0032] Returning to the flow of liquid 110 produced at the inlet facility 115, the flow of liquid 110 may flow to and be received by a water-oil separation system 180 (WOSEP). The water-oil separation system 180 may be configured to separate the flow of liquid 110 into a flow of crude oil 100a and second flow of water 130b. The flow of crude oil 100a may flow to and be received by the crude handling system 160.

[0033] Though FIG. 1 illustrates separate facilities and systems, any facility or system may be combined, in part or in whole, with any other facility or system without departing from the scope of the disclosure. For example, the crude handling system 160, in part or in whole, may be combined with the inlet facility 115.

[0034] Conventional GOSP operations may be performed within, for example, the inlet facility 115, crude handling system 160, and / or crude stabilization system 165. FIG. 2 illustrates conventional GOSP operations in accordance with one or more embodiments. In the conventional GOSP operations illustrated in FIG. 2, a flow of crude oil 100a flows through a crude oil feed 200. Though the flow of crude oil 100a undergoes various processes such that the flow of crude oil 100a may be pressurized, depressurized, degassed, dewatered, heated, refined, etc., the flow of crude oil 100a, no matter the process(es) it has undergone, will be generically referred to as the “flow of crude oil” when being received by an element of the conventional GOSP operations and as a “flow of treated crude oil” when being produced from the element hereinafter. This further applies to other flows, such as a “flow of gas” and “flow of water.”

[0035] Keeping with FIG. 2, a heat exchanger 205a (hereinafter “second heat exchanger”) may be disposed along the crude oil feed 200. The second heat exchanger 205a may be configured to receive the flow of crude oil 100a, heat the flow of crude oil 100a, using a flow of dry crude oil 100b, and produce a flow of treated crude oil 100a and flow of stable crude oil 100c. In other words, the second heat exchanger 205a transfers heat in the flow of dry crude oil 100b to the flow of crude oil 100a thereby heating the flow of crude oil 100a. In some embodiments, the second heat exchanger 205a may heat the flow of crude oil 100a to roughly between 100a° F. and 125° F. Further, in some embodiments, the second heat exchanger 205a may be a W / D heat exchanger. The flow of stable crude oil 100c may flow to and be received by a rundown cooler 207.

[0036] An LPDT 210 may be disposed along the crude oil feed 200 downstream of the second heat exchanger 205a. The LPDT 210 may be configured to receive the flow of crude oil 100a, separate a first flow of gas 105a from the flow of crude oil 100a, and produce a flow of treated crude oil 100a, first flow of gas 105a, and first flow of water 130a. The first flow of gas 105a may flow to and be received by an atmospheric compressor 215. The first flow of water 130a may flow to and be received by the water-oil separation system 180, as previously described relative to FIG. 1.

[0037] A first pump 220 may be disposed along the crude oil feed 200 downstream of the LPDT 210. The first pump 220 may be referred to as a “crude charge pump.” The first pump 220 may be configured to pressurize the flow of crude oil 100a.

[0038] Another second heat exchanger 205b may be disposed along the crude oil feed 200 downstream of the first pump 220. The second heat exchanger 205b may be configured to receive the flow of crude oil 100a, heat the flow of crude oil 100a, using a second flow of LP steam 225a, and produce a flow of treated crude oil 100a and a first flow of LP steam 225b. In some embodiments, the second heat exchanger 205b may be a trim heat exchanger. Further, in some embodiments, the second heat exchanger 205b may be disposed along a steam feed 230. A flow of LP steam 225a, b or flow of condensed steam may flow through the steam feed 230.

[0039] The crude handling system 160, as described relative to FIG. 1, may be disposed along the crude oil feed 200 downstream of the second heat exchanger 205b. The crude handling system 160 may be configured to receive the flow of crude oil 100a and produce a flow of treated crude oil 100a and second flow of water 130b. The second flow of water 130b may flow to and be received by the water-oil separation system 180, as previously described relative to FIG. 1.

[0040] Yet another second heat exchanger 205c may be disposed along the crude oil feed 200 downstream of the crude handling system 160. The second heat exchanger 205c may be configured to receive the flow of crude oil 100a, heat the flow of crude oil 100a, using a second flow of LP steam 225a, and produce a flow of treated crude oil 100a and first flow of LP steam 225b. Further, the second heat exchanger 205c may be disposed along the steam feed 230. In some embodiments, the second heat exchanger 205c may be a flash drum heat exchanger.

[0041] A flash drum 235, not to be confused with a flash drum heat exchanger, may be disposed along the crude oil feed 200 downstream of the second heat exchanger 205c. In some embodiments, the flash drum 235 may be part of the crude stabilization system 165 as described in FIG. 2. The flash drum 235 may be configured to receive the flow of crude oil 100a, separate a second flow of gas 105b from the flow of crude oil 100a, and produce the second flow of gas 105b and flow of dry crude oil 100b. In the flash drum 235, the pressure of the flow of crude oil 100a may be reduced suddenly to vaporize or “flash” the volatile components within the flow of crude oil 100a to thereby separate the second flow of gas 105b from the flow of crude oil 100a. The second flow of gas 105b may flow to and be received by the atmospheric compressor 215.

[0042] A second pump 240 may be disposed along the crude oil feed 200 downstream of the flash drum 235. The second pump 240 may be referred to as a “crude shipping pump”. The second pump 240 may be configured to pressurize the flow of dry crude oil 100b. The flow of dry crude oil 100b may flow to, be received by, and used by the second heat exchanger 205a.

[0043] The process associated with the crude oil feed 200 described immediately above may be cyclical as illustrated in FIG. 2 where the flow of dry crude oil 100b generated previously from the flow of crude oil 100a is used to heat the later flow of crude oil 100a, and, conversely, the flow of crude oil 100a cools the previously generated flow of dry crude oil 100b.

[0044] External to the crude oil feed 200, there may be the steam feed 230. A person of ordinary skill in the art will appreciate that additional hardware, such as valves, may be disposed along the steam feed 230, as well as the crude oil feed 200, to control the amount and / or rate of the flow flowing through each feed 200, 225.

[0045] A steam recovery system 245 may be disposed along the steam feed 230. The steam recovery system 245 may be configured to receive the first flow of LP steam 225b produced from one or more of the second heat exchangers 205b, c. In some embodiments, the steam recovery system 245 may be part of the inlet facility 115, gas compression system 120, and / or water-oil separation system 180 of the GOSP, as described relative to FIG. 1. The steam recovery system 245 may be further configured to produce a first flow of condensed steam 250a from the first flow of LP steam 225b.

[0046] A third pump 255 may be disposed along the steam feed 230. The third pump 255 may be referred to as a “condensed steam transfer pump.” The third pump 255 may be configured to pressurize the first flow of condensed steam 250a.

[0047] The first flow of condensed steam 250a is then cooled. The flow of condensed steam 250a may be cooled within the steam recovery system 245, along the steam feed 230, and / or at a steam generation system 260 using any cooling mechanism (not shown in FIG. 2) known to a person of ordinary skill in the art. Though the term “flow of condensed steam” is primarily used hereinafter, the first flow of condensed steam 250a may be cooled, either somewhat or completely. In instances where the term “flow of cooled condensed steam” is used, the first flow of condensed steam 250a may be cooled, either somewhat or completely. Further, a flow of cooled condensed steam may be synonymous to hot water.

[0048] Returning to FIG. 2, the first flow of condensed steam 250a may flow to and be received by the steam generation system 260. In some embodiments, the steam generation system 260 may be a part of a cogeneration plant (COGEN) external to the GOSP.

[0049] The steam generation system 260 may be configured to heat the first flow of condensed steam 250a to produce the second flow of LP steam 225a. The second flow of LP steam 225a may flow to, be received by, and used by one or more of the second heat exchangers 205b, 205c to heat the flow of crude oil 100a.

[0050] The process of producing LP steam from condensed steam and vice versa described immediately above may also be cyclical as illustrated in FIG. 2. As such, the two cyclical processes described above continuously heat the flow of crude oil 100a within the GOSP.

[0051] As described in FIG. 2, the conventional GOSP operations heavily rely on a second flow of LP steam 225a to heat a flow of crude oil 100a. Over the lifespan of the well producing the flow of crude oil 100a, the flow of crude oil 100a may include increased amounts of water (i.e., increased water cut). Further, seasonal changes may alter the amount of LP steam needed to heat the flow of crude oil 100a as the seasonal changes may affect the temperature of the flow of crude oil 100a. For example, the incoming flow of crude oil 100a may fluctuate between 106° F. and 121° F. depending on the season. Accordingly, the demand of LP steam needed to heat the flow of crude oil 100a in the conventional GOSP operations may fluctuate and / or increase. FIG. 3 shows a projection of the demand of LP steam needed to heat the flow of crude oil 100a flowing through a GOSP. The abscissa 300 shows the year. The ordinate 305 shows the demand of LP steam in kilopounds (i.e., kip) per hour.

[0052] To reduce the demand of LP steam needed to heat the flow of crude oil 100a in the GOSP, the disclosed system integrates a heat exchanger (hereinafter “first heat exchanger”) within the GOSP to heat the flow of crude oil 100a using the first flow of condensed steam 250a produced from the steam recovery system 245. The first heat exchanger may be referred to as a “condensed steam heat exchanger” or “heat-recovery-from-condensed-steam heat exchanger.”

[0053] Advantageously, the addition of the first heat exchanger offers at least one of the following benefits. The addition of the first heat exchanger may reduce the power (i.e., duty) of a separate cooling mechanism, or remove the need for a separate cooling mechanism, configured to cool the first flow of condensed steam 250a prior to or at the steam generation system 260. The addition of the first heat exchanger may also reduce the power of a second heat exchanger 205a-c, or even the need for a second heat exchanger 205a-c, as the first heat exchanger is aiding or supplementing the second heat exchanger 205a-c in heating the flow of crude oil 100a. Both benefits may save energy. Further, the first heat exchanger may allow a downstream LPDT 210 to separate more gas and / or water from the flow of crude oil 100a due to the higher temperature of the flow of crude oil 100a. Accordingly, the power of downstream second heat exchangers 205b, c and the demand of LP steam needed by the downstream second heat exchangers 205b, c may be reduced. Further, the power of an atmospheric compressor 215 may be reduced. Still further, the power of a downstream flash drum 235 may be reduced.

[0054] Still further, costs associated with operating the GOSP and / or steam generation system 260 (i.e., OpEx) and / or maintaining the GOSP and / or steam generation system 260 (i.e., CapEx) may be reduced. For example, a lower-capacity steam generation system 260 and second heat exchangers 205a-c could be used now that less demand is needed. Further, heat produced from the first flow of condensed steam 250a that may have previously been released into the atmosphere is now being harnessed to heat the flow of crude oil 100a. The addition of the first heat exchanger may also reduce the demand of LP steam used within a GOSP. Accordingly, costs associated with operating the GOSP (i.e., OpEx) may be further reduced. Further, the addition of the first heat exchanger may reduce the impact a GOSP has on the environment and the carbon footprint (e.g., CO2 emissions) of the GOSP due to the reduction of the demand of LP steam and other heat sources.

[0055] FIGS. 4-6 illustrate the disclosed system in accordance with one or more embodiments. The disclosed system may be implemented, in part or in whole, within a GOSP. For example, the disclosed system may be implemented, in part or in whole, within the inlet facility 115, crude handling system 160, or crude stabilization system 165 of a GOSP. Further, the disclosed system may be implemented continuously or intermittently. For example, in some embodiments, the disclosed system may be dormant in the summer and active in the winter when the flow of crude oil 100a is colder. Further, in some embodiments, the disclosed system may be dormant when the water content in the flow of crude oil 100a is low and active when the water content is high.

[0056] In each of FIGS. 4-6, the first heat exchanger 400a-c is disposed along the crude oil feed 200 at a unique position in accordance with one or more embodiments. However, a person of ordinary skill in the art will appreciate that the first heat exchanger 400a-c may be disposed at other positions along the crude oil feed 200 and / or multiple positions along the crude oil feed 200 without departing from the disclosure. Further, a person of ordinary skill in the art will appreciate that the first heat exchanger 400a-c may replace the second heat exchanger 205a-c.

[0057] Referring to FIG. 4, the first heat exchanger 400a is disposed along the crude oil feed 200 upstream of the LPDT 210 and downstream of the second heat exchanger 205a. The first heat exchanger 400a is further disposed along the steam feed 230. In comparing the conventional GOSP operations of FIG. 2 to the disclosed system of FIG. 4, the first flow of condensed steam 250a produced from the steam recovery system 245 now flows to and is received by the first heat exchanger 400a at a first position in contrast to being received by the steam generation system 260 in the conventional GOSP operations. The first heat exchanger 400a is configured to receive the first flow of condensed steam 250a and flow of crude oil 100a, heat the flow of crude oil 100a using the first flow of condensed steam 250a, and produce a flow of treated crude oil 100a and second flow of condensed steam 250b. In other words, the first heat exchanger 400a transfers heat from the first flow of condensed steam 250a to the flow of crude oil 100a. Accordingly, the flow of treaded crude oil 100a is heated and the second flow of condensed steam 250b is cooled.

[0058] The second flow of condensed steam 250b flows to and is received by the steam generation system 260. In contrast to the conventional GOSP operations, the first heat exchanger 400a may act as a cooling mechanism to cool the first flow of condensed steam 250a prior to being received by the steam generation system 260. Accordingly, a separate cooling mechanism, as may be used in the conventional GOSP operations, may not be needed in the disclosed system or the disclosed system reduces the power of a separate cooling mechanism. Further, the power of one or more of the second heat exchangers 205a-c may be reduced as the first heat exchanger 400a is supplementing the second heat exchangers 205a-c and other systems disposed along the crude oil feed 200 that are configured to heat the flow of crude oil 100a.

[0059] Turning to FIG. 5, the first heat exchanger 400b is disposed along the crude oil feed 200 upstream of the second heat exchanger 205b and downstream of the LPDT 210. Similar to FIG. 4, the first flow of condensed steam 250a produced from the steam recovery system 245 flows to and is received by the first heat exchanger 400b at a second position.

[0060] Turning to FIG. 6, the first heat exchanger 400c is disposed along the crude oil feed 200 upstream of the second heat exchanger 205c and downstream of the crude handling system 160. Similar to FIGS. 4 and 5, the first flow of condensed steam 250a produced from the steam recovery system 245 flows to and is received by the first heat exchanger 400c at a third position.

[0061] Note the description of the other elements shown in FIGS. 4-6 are previously described relative to FIG. 2. Accordingly, for brevity, the description of the other elements shown in FIGS. 2 and 4-6 is not duplicated relative to FIGS. 4-6.

[0062] In disposing one or more first heat exchangers 400a-c along the crude oil feed 200, additional power may need to be supplied to the third pump 255 to ensure the first flow of condensed steam 250a flows to each of the one or more first heat exchangers 400a-c at a prescribed temperature, velocity, and / or pressure. In some embodiments, the additional power needed when one first heat exchanger 400a-c is disposed along the crude oil feed 200 may be around 74 horsepower (hp).

[0063] In some embodiments, sensors and / or other instruments may be permanently or temporarily disposed along the crude oil feed 200 and / or steam feed 230 to measure various properties of the flow of crude oil 100a and / or flows of steam 225a, b and 250a, b such as, without limitation, temperature, power, velocity, or fluid composition. Further, the ambient temperature of the GOSP may be measured as the temperature may fluctuate seasonally. Such measurements may be used to design the disclosed system such that the disclosed system adequately heats the flow of crude oil 100a.

[0064] FIG. 7 describes a method in accordance with one or more embodiments. One or more steps described relative to FIG. 7 may be repeated and / or omitted. Further, the steps may be performed in a different order without departing from the scope of the disclosure.

[0065] In step 700, a flow of crude oil 100a is received in a crude oil feed 200. In some embodiments, the flow of crude oil 100a may be raw crude oil. The raw crude oil may be extracted from a hydrocarbon reservoir located below ground using a well. In other embodiments, the flow of crude oil 100a may include treated crude oil. In some embodiments, the crude oil feed 200 may be part of a GOSP.

[0066] In step 705, a steam recovery system 245 receives a first flow of LP steam 225b. In some embodiments, the steam recovery system 245 is disposed along a steam feed 230 within the GOSP. Further, in some embodiments, the first flow of LP steam 225b is produced by a second heat exchanger 205b, c disposed along the crude oil feed 200. To produce the first flow of LP steam 225b, the second heat exchanger 205b, c may receive a second flow of LP steam 225a (produced from the steam generation system 260) and the flow of crude oil 100a.

[0067] In step 710, the steam recovery system 245 produces a first flow of condensed steam 250a from the first flow of LP steam 225b.

[0068] In step 715, a first heat exchanger 400a-c receives the flow of crude oil 100a and the first flow of condensed steam 250a. The first heat exchanger 400a-c may be disposed along the crude oil feed 200.

[0069] In step 720, the first heat exchanger 400a-c produces a first flow of treated crude oil 100a from the flow of crude oil 100a using the first flow of condensed steam 250a. In other words, heat within the first flow of condensed steam 250a is exchanged with the flow of crude oil 100a to produce a flow of heated crude oil 100a. In some embodiments, the first heat exchanger 400a-c further produces a second flow of condensed steam 250b. Accordingly, the second flow of condensed steam 250b may be cooler than the first flow of condensed steam 250a. In these embodiments, the second flow of condensed steam 250b may be received by the steam generation system 260. In some embodiments, the steam generation system 260 may be disposed along the steam feed 230.

[0070] In some embodiments, a flash drum 235 disposed along the crude oil feed 200 may receive the flow of treated crude oil 100a and produce a flow of dry crude oil 100b and / or flow of gas 105b. In these embodiments, a second heat exchanger 205a disposed along the crude oil feed 200 may receive the flow of dry crude oil 100b and use the flow of dry crude oil 100b to produce a flow of crude oil 100a that is heated.

[0071] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the below claims.EXAMPLES

[0072] Hereinafter, projections of how the disclosed systems may operate within a GOSP in the future are provided as compared to how the conventional GOSP operations described relative to FIG. 2 may operate. The projections are determined by simulating the conventional GOSP operations and disclosed system. Hereinafter, the disclosed system described relative to FIG. 4 is denoted “configuration 1” or “C1,” the disclosed system described relative to FIG. 5 is denoted “configuration 2” or “C2,” and the disclosed system described relative to FIG. 6 is denoted “configuration 3” or “C3.”

[0073] Table 1 provides projections of GOSP-related metrics associated with the conventional GOSP operations as described in FIG. 2 (denoted “B” in Table 1) relative to C1, C2, and C3. The projections are provided for the years 2035 and 2051. In these examples, the second heat exchanger 205b is a trim heat exchanger, the second heat exchanger 205c is a flash drum heat exchanger, and the first pump 220 is a crude charge pump. Assumptions include that the flow of crude oil 100a is at least 150° F. prior to reaching the trim heat exchanger, that the flow of dry crude oil 100b meets various export standards, such as the temperature of the flow of dry crude oil 100b being between 178° F. to 191° F.TABLE 1Year20352051MetricUnitsBC1C2C3BC1C2C3SteamMMBtu / hr025.242.4081.681.8CondensateHeater PowerTemperature° F.11712392102into LPDTGas fromMillion13.414.913.315.5LPDTstandardcubic feetper day(MMSCFD)TrimMMBtu / hr115.293.186.4352.3289.2276.3ExchangerPowerTrimklb / hr126101.994.5385.4316.4302.2ExchangerSteamDemandFlash Drum° F.148157148165HeatExchangerInletTemperatureFlash Drum° F.178177191186HeatExchangerOutletTemperatureFlash DrumMMBtu / hr70.467.754.9102.289.363.2HeatExchangerPowerFlash Drumklb / hr77.174.160.1111.897.769.1HeatExchangerSteamDemandGas fromMMSCFD14.312.420.318Flash DrumGas toMMSCFD27.727.333.633.4AtmosphericCompressorAtmosphericHp3238318739023859CompressorPowerCrude ChargeHp1583179715831797Pump PowerReduction inMMBtu / hr24.776Heat DemandReduction inKlb / hr27.183.1SteamDemandReduction inHp—−238−74−74—−246−74−74PowerRequirementTotal EnergyMegawatt—7.068.394.49—22.122.211.37Savings(MW)

[0074] Table 2 provides projections of GOSP-related metrics associated with C1, C2, and C3 relative to costs and CO2 emissions. Note maintenance costs are considered every 5 years.TABLE 2CO2CO2InitiativeEmissionsEmissionsNetChange -Change -OverallCapExPresentfrom fuelfromCO2DifferenceValuegaselectricityEmissionsMillions(NPV)consumptionproductionChangeC($MM)$MMKilotonsKilotonsKilotons15.93−3.32−4373.72−43326.20−0.36−6891.15−68836.37−3.68−3341.15−332

[0075] Tables 1 and 2 show that the disclosed system may be technically and economically viable.

Examples

examples

[0072]Hereinafter, projections of how the disclosed systems may operate within a GOSP in the future are provided as compared to how the conventional GOSP operations described relative to FIG. 2 may operate. The projections are determined by simulating the conventional GOSP operations and disclosed system. Hereinafter, the disclosed system described relative to FIG. 4 is denoted “configuration 1” or “C1,” the disclosed system described relative to FIG. 5 is denoted “configuration 2” or “C2,” and the disclosed system described relative to FIG. 6 is denoted “configuration 3” or “C3.”

[0073]Table 1 provides projections of GOSP-related metrics associated with the conventional GOSP operations as described in FIG. 2 (denoted “B” in Table 1) relative to C1, C2, and C3. The projections are provided for the years 2035 and 2051. In these examples, the second heat exchanger 205b is a trim heat exchanger, the second heat exchanger 205c is a flash drum heat exchanger, and the first pump 220 is a c...

BACKGROUND

[0001] In the upstream oil and gas industry, a gas-oil separation plant (GOSP) is configured to separate gas and liquid components from wild raw crude oil using distillation. The wild raw crude oil may flow from a reservoir below ground through a well and into a pipeline above ground that transports the wild raw crude oil to the GOSP.

[0002] At the GOSP, various forms of energy are used to help separate the gas and liquid components from the wild raw crude oil to produce stable crude oil. Some energy may be transferred to the GOSP from external facilities while excess residual energy produced at the GOSP as a byproduct of separating the wild raw crude oil may be transferred to external facilities once cooled.SUMMARY

[0003] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0004] In general, in one aspect, embodiments relate to a system. The system includes a crude oil feed, steam recovery system, and first heat exchanger. The crude oil feed is configured to receive a flow of crude oil. The steam recovery system is configured to receive a first flow of low-pressure steam and produce a first flow of condensed steam. The first heat exchanger is disposed along the crude oil feed. The first heat exchanger is configured to receive the flow of crude oil and the first flow of condensed steam and produce, using the first flow of condensed steam, a first flow of treated crude oil from the flow of crude oil.

[0005] In general, in one aspect, embodiments relate to a method. The method includes receiving, in a crude oil feed, a flow of crude oil and receiving, by a steam recovery system, a first flow of low-pressure steam. The method further includes producing, from the steam recovery system, a first flow of condensed steam from the first flow of low-pressure steam and receiving, by a first heat exchanger, the flow of crude oil and the first flow of condensed steam. The method still further includes producing, from the first heat exchanger using the first flow of condensed steam, a first flow of treated crude oil from the flow of crude oil.

[0006] Any combinations of the various embodiments and implementations disclosed herein can be used in a further embodiment, consistent with the disclosure. Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.BRIEF DESCRIPTION OF DRAWINGS

[0007] FIG. 1 shows a flowchart of GOSP-related systems in accordance with one or more embodiments.

[0008] FIG. 2 shows a flowchart of conventional GOSP operations in accordance with one or more embodiments.

[0009] FIG. 3 shows a projection of low-pressure steam demand in accordance with one or more embodiments.

[0010] FIGS. 4-6 show a flowchart of disclosed systems in accordance with one or more embodiments.

[0011] FIG. 7 shows a method in accordance with one or more embodiments.DETAILED DESCRIPTION

[0012] In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

[0013] Throughout the application, ordinal numbers (for example, first, second, third) may be used as an adjective for an element (that is, any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.

[0014] It is to be understood that the singular forms “a,”“an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to “a fluid sample” includes reference to one or more of such samples.

[0015] Terms such as “approximately,”“substantially,” etc., mean that the recited characteristic, parameter, or value need not be achieved exactly, but that deviations or variations, including for example, tolerances, measurement error, measurement accuracy limitations and other factors known to those of skill in the art, may occur in amounts that do not preclude the effect the characteristic was intended to provide.

[0016] It is to be understood that one or more of the steps shown in the flowcharts may be omitted, repeated, and / or performed in a different order than the order shown. Accordingly, the scope of the invention should not be considered limited to the specific arrangement of steps shown in the flowcharts.

[0017] Although multiple dependent claims are not introduced, it would be apparent to one of ordinary skill that the subject matter of the dependent claims of one or more embodiments may be combined with other dependent claims.

[0018] Embodiments disclosed herein relate to a system and methods of using the same. In some embodiments, the system may be included, in part, within a gas-oil separation plant (GOSP). The GOSP may be configured to separate gas and liquid components from raw crude oil using various forms of energy thereby purifying the raw crude oil. The purification process may be referred to as distillation.

[0019] Systems that may be used in a conventional GOSP are shown in FIG. 1. Specifically, FIG. 1 shows a flowchart of the systems in accordance with one or more embodiments. Note the systems described below are for illustration purposes only and are not intended to limit the scope of the disclosure.

[0020] Upstream of the GOSP, a flow of crude oil 100a may be extracted from a hydrocarbon reservoir located below ground using a well. Though the generic term “flow of crude oil” is primarily used throughout the disclosure, the flow of crude oil 100a may be a flow of wet crude oil. Wet crude oil is defined as untreated crude oil that contains water, gas, and sediment. Further, wet crude oil may be synonymous to “wild crude oil,”“raw crude oil,” or “wild raw crude oil.” Above ground, the flow of crude oil 100a may flow through one or more crude oil feeds (e.g., pipelines) towards the GOSP. On the way, the flow of crude oil 100a may be split such that a portion of the flow of crude oil 100a reaches each of multiple GOSPs. In other words, multiple GOSPs may be configured to separate a first flow of gas 105a and flow of liquid 110 from the flow of crude oil 100a. In some embodiments, a central processing facility (CPF) may include the multiple GOSPs operating in series and / or parallel. In these embodiments, the CPF may receive hundreds of thousands of barrels of crude oil per day. Further, in these embodiments, each GOSP may receive a flow of crude oil 100a with common gas compression, dehydration, and dew point control.

[0021] Keeping with FIG. 1, at the GOSP, the flow of crude oil 100a may flow to and be received by an inlet facility 115. The inlet facility 115 may be configured to largely—though maybe not completely—separate the first flow of gas 105a and flow of liquid 110 from the flow of crude oil 100a. Accordingly, each of the flow of crude oil 100a, first flow of gas 105a, and flow of liquid 110 may contain impurities and / or other types of flows. For example, the flow of liquid 110 may include a mixture of water and crude oil.

[0022] The inlet facility 115 may include separators such as, without limitation, production traps, heat exchangers, and low-pressure degassing tanks (LPDT). In some embodiments, the production trap may include a high-pressure production trap (HPPT), low-pressure production trap (LPPT), or combination thereof. The pressure of a combined HPPT and LPPT may depend on the arrival of the pressure and amount of gas in the flow of crude oil 100a. The heat exchanger may include a trim heat exchanger, wet and dry (W / D) heat exchanger, flash drum heat exchanger, condensed steam heat exchanger, or combination thereof. In some embodiments, a trim heat exchanger may include a shell and tube and be configured to heat, using a flow of LP steam, a flow of crude oil 100a. In some embodiments, a wet and dry (W / D) heat exchanger may include a shell and tube and be configured to heat, using a flow of dry crude oil, a flow of crude oil 100a after the flow of crude oil 100a passes through a production trap. Dry crude oil may be defined as crude oil with negligible amounts of water, gas, and / or sediment. Hereinafter the generic term “heat exchanger” may be used to describe any type of heat exchanger. Each separator in the inlet facility 115 may be a two-phase separator to separate the first flow of gas 105a from the flow of crude oil 100a or a three-phase separator to separate the first flow of gas 105a and flow of liquid 110 from the flow of crude oil 100a. Note the process of separating a flow of liquid 110 that contains water from a flow of crude oil 100a is known as dewatering.

[0023] The first flow of gas 105a may flow to and be received by a gas compression system 120. The gas compression system 120 may be configured to compress the first flow of gas 105a to produce a flow of compressed gas 105b, first flow of condensate 125a (e.g., non-water liquid), and first flow of water 130a. To do so, the gas compression system 120 may include, without limitation, gas compressors, heat exchangers, knockout drums, and cooling mechanisms.

[0024] The flow of compressed gas 105b may flow to and be received by a gas treatment system 135. The gas treatment system 135 may be configured to reduce impurities in the flow of compressed gas 105b to produce a flow of treated gas 105c and second flow of condensate 125b. Impurities may include hydrogen sulfide and carbon dioxide (CO2). The gas treatment system 135 may rely on mechanical and / or chemical means to reduce impurities.

[0025] The flow of treated gas 105c may then flow to and be received by a pipeline compression system 140. The pipeline compression system 140 may be configured to further compress the flow of treated gas 105c. The flow of treated compressed gas 105d may then flow to and be received by a dry gas downstream facility 145 outside the GOSP.

[0026] The flows of condensate 125a, b produced at the gas compression system 120 and / or gas treatment system 135 may flow to and be received by the condensate storage and export facility 150. The flows of condensate 125a, b may include hydrocarbon condensate and / or water condensate. The condensate storage and export facility 150 may be configured to prepare the flows of condensate 125a, b to be sent to and received by a condensate downstream facility 155 outside the GOSP.

[0027] Returning to the first flow of water 130a produced at the gas compression system 120, the first flow of water 130a may include hydrocarbons. As such, the first flow of water 130a may flow to and be received by a crude handling system 160 configured to extract the hydrocarbons from the first flow of water 130a.

[0028] Returning to the flow of crude oil 100a produced at the inlet facility 115, the flow of crude oil 100a may flow to and be received by the crude handling system 160. The crude handling system 160 may be configured to separate the flow of crude oil 100a into a flow of crude oil 100a and second flow of water 130b. To do so, the crude handling system 160 may include separators such as, without limitation, desalting systems, gas removal systems, heat exchangers, dehydrators, water knockout drums, and settling tanks. Desalting may be performed by extracting the second flow of water 130b, which may include salt, from the flow of crude oil 100a. Examples of desalting systems include first stage desalters and second stage desalters. The heat exchanger may include a flash drum. The flash drum may include a shell and tube and be configured to heat a flow of dry crude output from a second stage desalter using a flow of LP steam.

[0029] The flow of crude oil 100a produced at the crude handling system 160 may flow to and be received by a crude stabilization system 165. The crude stabilization system 165 may be configured to largely separate volatile components from the flow of crude oil 100a to produce a flow of crude oil 100a and second flow of gas 105e. Volatile components may include light hydrocarbons such as, without limitation, methane, ethane, propane, and butane. To separate volatile components, the crude stabilization system 165 may include separators such as, without limitation, stabilizer columns, stabilizer towers, stripping columns, and heat exchangers. The stripping columns may strip dissolved gases (e.g., natural gas) from the flow of crude oil 100a.

[0030] The second flow of gas 105e may flow to and be received by the gas treatment system 135.

[0031] The flow of crude oil 100a may flow to and be received by the crude storage and export facility 170. The crude storage and export facility 170 may be configured to prepare the flow of crude oil 100a to be sent to and received by a crude downstream facility 175 outside the GOSP.

[0032] Returning to the flow of liquid 110 produced at the inlet facility 115, the flow of liquid 110 may flow to and be received by a water-oil separation system 180 (WOSEP). The water-oil separation system 180 may be configured to separate the flow of liquid 110 into a flow of crude oil 100a and second flow of water 130b. The flow of crude oil 100a may flow to and be received by the crude handling system 160.

[0033] Though FIG. 1 illustrates separate facilities and systems, any facility or system may be combined, in part or in whole, with any other facility or system without departing from the scope of the disclosure. For example, the crude handling system 160, in part or in whole, may be combined with the inlet facility 115.

[0034] Conventional GOSP operations may be performed within, for example, the inlet facility 115, crude handling system 160, and / or crude stabilization system 165. FIG. 2 illustrates conventional GOSP operations in accordance with one or more embodiments. In the conventional GOSP operations illustrated in FIG. 2, a flow of crude oil 100a flows through a crude oil feed 200. Though the flow of crude oil 100a undergoes various processes such that the flow of crude oil 100a may be pressurized, depressurized, degassed, dewatered, heated, refined, etc., the flow of crude oil 100a, no matter the process(es) it has undergone, will be generically referred to as the “flow of crude oil” when being received by an element of the conventional GOSP operations and as a “flow of treated crude oil” when being produced from the element hereinafter. This further applies to other flows, such as a “flow of gas” and “flow of water.”

[0035] Keeping with FIG. 2, a heat exchanger 205a (hereinafter “second heat exchanger”) may be disposed along the crude oil feed 200. The second heat exchanger 205a may be configured to receive the flow of crude oil 100a, heat the flow of crude oil 100a, using a flow of dry crude oil 100b, and produce a flow of treated crude oil 100a and flow of stable crude oil 100c. In other words, the second heat exchanger 205a transfers heat in the flow of dry crude oil 100b to the flow of crude oil 100a thereby heating the flow of crude oil 100a. In some embodiments, the second heat exchanger 205a may heat the flow of crude oil 100a to roughly between 100a° F. and 125° F. Further, in some embodiments, the second heat exchanger 205a may be a W / D heat exchanger. The flow of stable crude oil 100c may flow to and be received by a rundown cooler 207.

[0036] An LPDT 210 may be disposed along the crude oil feed 200 downstream of the second heat exchanger 205a. The LPDT 210 may be configured to receive the flow of crude oil 100a, separate a first flow of gas 105a from the flow of crude oil 100a, and produce a flow of treated crude oil 100a, first flow of gas 105a, and first flow of water 130a. The first flow of gas 105a may flow to and be received by an atmospheric compressor 215. The first flow of water 130a may flow to and be received by the water-oil separation system 180, as previously described relative to FIG. 1.

[0037] A first pump 220 may be disposed along the crude oil feed 200 downstream of the LPDT 210. The first pump 220 may be referred to as a “crude charge pump.” The first pump 220 may be configured to pressurize the flow of crude oil 100a.

[0038] Another second heat exchanger 205b may be disposed along the crude oil feed 200 downstream of the first pump 220. The second heat exchanger 205b may be configured to receive the flow of crude oil 100a, heat the flow of crude oil 100a, using a second flow of LP steam 225a, and produce a flow of treated crude oil 100a and a first flow of LP steam 225b. In some embodiments, the second heat exchanger 205b may be a trim heat exchanger. Further, in some embodiments, the second heat exchanger 205b may be disposed along a steam feed 230. A flow of LP steam 225a, b or flow of condensed steam may flow through the steam feed 230.

[0039] The crude handling system 160, as described relative to FIG. 1, may be disposed along the crude oil feed 200 downstream of the second heat exchanger 205b. The crude handling system 160 may be configured to receive the flow of crude oil 100a and produce a flow of treated crude oil 100a and second flow of water 130b. The second flow of water 130b may flow to and be received by the water-oil separation system 180, as previously described relative to FIG. 1.

[0040] Yet another second heat exchanger 205c may be disposed along the crude oil feed 200 downstream of the crude handling system 160. The second heat exchanger 205c may be configured to receive the flow of crude oil 100a, heat the flow of crude oil 100a, using a second flow of LP steam 225a, and produce a flow of treated crude oil 100a and first flow of LP steam 225b. Further, the second heat exchanger 205c may be disposed along the steam feed 230. In some embodiments, the second heat exchanger 205c may be a flash drum heat exchanger.

[0041] A flash drum 235, not to be confused with a flash drum heat exchanger, may be disposed along the crude oil feed 200 downstream of the second heat exchanger 205c. In some embodiments, the flash drum 235 may be part of the crude stabilization system 165 as described in FIG. 2. The flash drum 235 may be configured to receive the flow of crude oil 100a, separate a second flow of gas 105b from the flow of crude oil 100a, and produce the second flow of gas 105b and flow of dry crude oil 100b. In the flash drum 235, the pressure of the flow of crude oil 100a may be reduced suddenly to vaporize or “flash” the volatile components within the flow of crude oil 100a to thereby separate the second flow of gas 105b from the flow of crude oil 100a. The second flow of gas 105b may flow to and be received by the atmospheric compressor 215.

[0042] A second pump 240 may be disposed along the crude oil feed 200 downstream of the flash drum 235. The second pump 240 may be referred to as a “crude shipping pump”. The second pump 240 may be configured to pressurize the flow of dry crude oil 100b. The flow of dry crude oil 100b may flow to, be received by, and used by the second heat exchanger 205a.

[0043] The process associated with the crude oil feed 200 described immediately above may be cyclical as illustrated in FIG. 2 where the flow of dry crude oil 100b generated previously from the flow of crude oil 100a is used to heat the later flow of crude oil 100a, and, conversely, the flow of crude oil 100a cools the previously generated flow of dry crude oil 100b.

[0044] External to the crude oil feed 200, there may be the steam feed 230. A person of ordinary skill in the art will appreciate that additional hardware, such as valves, may be disposed along the steam feed 230, as well as the crude oil feed 200, to control the amount and / or rate of the flow flowing through each feed 200, 225.

[0045] A steam recovery system 245 may be disposed along the steam feed 230. The steam recovery system 245 may be configured to receive the first flow of LP steam 225b produced from one or more of the second heat exchangers 205b, c. In some embodiments, the steam recovery system 245 may be part of the inlet facility 115, gas compression system 120, and / or water-oil separation system 180 of the GOSP, as described relative to FIG. 1. The steam recovery system 245 may be further configured to produce a first flow of condensed steam 250a from the first flow of LP steam 225b.

[0046] A third pump 255 may be disposed along the steam feed 230. The third pump 255 may be referred to as a “condensed steam transfer pump.” The third pump 255 may be configured to pressurize the first flow of condensed steam 250a.

[0047] The first flow of condensed steam 250a is then cooled. The flow of condensed steam 250a may be cooled within the steam recovery system 245, along the steam feed 230, and / or at a steam generation system 260 using any cooling mechanism (not shown in FIG. 2) known to a person of ordinary skill in the art. Though the term “flow of condensed steam” is primarily used hereinafter, the first flow of condensed steam 250a may be cooled, either somewhat or completely. In instances where the term “flow of cooled condensed steam” is used, the first flow of condensed steam 250a may be cooled, either somewhat or completely. Further, a flow of cooled condensed steam may be synonymous to hot water.

[0048] Returning to FIG. 2, the first flow of condensed steam 250a may flow to and be received by the steam generation system 260. In some embodiments, the steam generation system 260 may be a part of a cogeneration plant (COGEN) external to the GOSP.

[0049] The steam generation system 260 may be configured to heat the first flow of condensed steam 250a to produce the second flow of LP steam 225a. The second flow of LP steam 225a may flow to, be received by, and used by one or more of the second heat exchangers 205b, 205c to heat the flow of crude oil 100a.

[0050] The process of producing LP steam from condensed steam and vice versa described immediately above may also be cyclical as illustrated in FIG. 2. As such, the two cyclical processes described above continuously heat the flow of crude oil 100a within the GOSP.

[0051] As described in FIG. 2, the conventional GOSP operations heavily rely on a second flow of LP steam 225a to heat a flow of crude oil 100a. Over the lifespan of the well producing the flow of crude oil 100a, the flow of crude oil 100a may include increased amounts of water (i.e., increased water cut). Further, seasonal changes may alter the amount of LP steam needed to heat the flow of crude oil 100a as the seasonal changes may affect the temperature of the flow of crude oil 100a. For example, the incoming flow of crude oil 100a may fluctuate between 106° F. and 121° F. depending on the season. Accordingly, the demand of LP steam needed to heat the flow of crude oil 100a in the conventional GOSP operations may fluctuate and / or increase. FIG. 3 shows a projection of the demand of LP steam needed to heat the flow of crude oil 100a flowing through a GOSP. The abscissa 300 shows the year. The ordinate 305 shows the demand of LP steam in kilopounds (i.e., kip) per hour.

[0052] To reduce the demand of LP steam needed to heat the flow of crude oil 100a in the GOSP, the disclosed system integrates a heat exchanger (hereinafter “first heat exchanger”) within the GOSP to heat the flow of crude oil 100a using the first flow of condensed steam 250a produced from the steam recovery system 245. The first heat exchanger may be referred to as a “condensed steam heat exchanger” or “heat-recovery-from-condensed-steam heat exchanger.”

[0053] Advantageously, the addition of the first heat exchanger offers at least one of the following benefits. The addition of the first heat exchanger may reduce the power (i.e., duty) of a separate cooling mechanism, or remove the need for a separate cooling mechanism, configured to cool the first flow of condensed steam 250a prior to or at the steam generation system 260. The addition of the first heat exchanger may also reduce the power of a second heat exchanger 205a-c, or even the need for a second heat exchanger 205a-c, as the first heat exchanger is aiding or supplementing the second heat exchanger 205a-c in heating the flow of crude oil 100a. Both benefits may save energy. Further, the first heat exchanger may allow a downstream LPDT 210 to separate more gas and / or water from the flow of crude oil 100a due to the higher temperature of the flow of crude oil 100a. Accordingly, the power of downstream second heat exchangers 205b, c and the demand of LP steam needed by the downstream second heat exchangers 205b, c may be reduced. Further, the power of an atmospheric compressor 215 may be reduced. Still further, the power of a downstream flash drum 235 may be reduced.

[0054] Still further, costs associated with operating the GOSP and / or steam generation system 260 (i.e., OpEx) and / or maintaining the GOSP and / or steam generation system 260 (i.e., CapEx) may be reduced. For example, a lower-capacity steam generation system 260 and second heat exchangers 205a-c could be used now that less demand is needed. Further, heat produced from the first flow of condensed steam 250a that may have previously been released into the atmosphere is now being harnessed to heat the flow of crude oil 100a. The addition of the first heat exchanger may also reduce the demand of LP steam used within a GOSP. Accordingly, costs associated with operating the GOSP (i.e., OpEx) may be further reduced. Further, the addition of the first heat exchanger may reduce the impact a GOSP has on the environment and the carbon footprint (e.g., CO2 emissions) of the GOSP due to the reduction of the demand of LP steam and other heat sources.

[0055] FIGS. 4-6 illustrate the disclosed system in accordance with one or more embodiments. The disclosed system may be implemented, in part or in whole, within a GOSP. For example, the disclosed system may be implemented, in part or in whole, within the inlet facility 115, crude handling system 160, or crude stabilization system 165 of a GOSP. Further, the disclosed system may be implemented continuously or intermittently. For example, in some embodiments, the disclosed system may be dormant in the summer and active in the winter when the flow of crude oil 100a is colder. Further, in some embodiments, the disclosed system may be dormant when the water content in the flow of crude oil 100a is low and active when the water content is high.

[0056] In each of FIGS. 4-6, the first heat exchanger 400a-c is disposed along the crude oil feed 200 at a unique position in accordance with one or more embodiments. However, a person of ordinary skill in the art will appreciate that the first heat exchanger 400a-c may be disposed at other positions along the crude oil feed 200 and / or multiple positions along the crude oil feed 200 without departing from the disclosure. Further, a person of ordinary skill in the art will appreciate that the first heat exchanger 400a-c may replace the second heat exchanger 205a-c.

[0057] Referring to FIG. 4, the first heat exchanger 400a is disposed along the crude oil feed 200 upstream of the LPDT 210 and downstream of the second heat exchanger 205a. The first heat exchanger 400a is further disposed along the steam feed 230. In comparing the conventional GOSP operations of FIG. 2 to the disclosed system of FIG. 4, the first flow of condensed steam 250a produced from the steam recovery system 245 now flows to and is received by the first heat exchanger 400a at a first position in contrast to being received by the steam generation system 260 in the conventional GOSP operations. The first heat exchanger 400a is configured to receive the first flow of condensed steam 250a and flow of crude oil 100a, heat the flow of crude oil 100a using the first flow of condensed steam 250a, and produce a flow of treated crude oil 100a and second flow of condensed steam 250b. In other words, the first heat exchanger 400a transfers heat from the first flow of condensed steam 250a to the flow of crude oil 100a. Accordingly, the flow of treaded crude oil 100a is heated and the second flow of condensed steam 250b is cooled.

[0058] The second flow of condensed steam 250b flows to and is received by the steam generation system 260. In contrast to the conventional GOSP operations, the first heat exchanger 400a may act as a cooling mechanism to cool the first flow of condensed steam 250a prior to being received by the steam generation system 260. Accordingly, a separate cooling mechanism, as may be used in the conventional GOSP operations, may not be needed in the disclosed system or the disclosed system reduces the power of a separate cooling mechanism. Further, the power of one or more of the second heat exchangers 205a-c may be reduced as the first heat exchanger 400a is supplementing the second heat exchangers 205a-c and other systems disposed along the crude oil feed 200 that are configured to heat the flow of crude oil 100a.

[0059] Turning to FIG. 5, the first heat exchanger 400b is disposed along the crude oil feed 200 upstream of the second heat exchanger 205b and downstream of the LPDT 210. Similar to FIG. 4, the first flow of condensed steam 250a produced from the steam recovery system 245 flows to and is received by the first heat exchanger 400b at a second position.

[0060] Turning to FIG. 6, the first heat exchanger 400c is disposed along the crude oil feed 200 upstream of the second heat exchanger 205c and downstream of the crude handling system 160. Similar to FIGS. 4 and 5, the first flow of condensed steam 250a produced from the steam recovery system 245 flows to and is received by the first heat exchanger 400c at a third position.

[0061] Note the description of the other elements shown in FIGS. 4-6 are previously described relative to FIG. 2. Accordingly, for brevity, the description of the other elements shown in FIGS. 2 and 4-6 is not duplicated relative to FIGS. 4-6.

[0062] In disposing one or more first heat exchangers 400a-c along the crude oil feed 200, additional power may need to be supplied to the third pump 255 to ensure the first flow of condensed steam 250a flows to each of the one or more first heat exchangers 400a-c at a prescribed temperature, velocity, and / or pressure. In some embodiments, the additional power needed when one first heat exchanger 400a-c is disposed along the crude oil feed 200 may be around 74 horsepower (hp).

[0063] In some embodiments, sensors and / or other instruments may be permanently or temporarily disposed along the crude oil feed 200 and / or steam feed 230 to measure various properties of the flow of crude oil 100a and / or flows of steam 225a, b and 250a, b such as, without limitation, temperature, power, velocity, or fluid composition. Further, the ambient temperature of the GOSP may be measured as the temperature may fluctuate seasonally. Such measurements may be used to design the disclosed system such that the disclosed system adequately heats the flow of crude oil 100a.

[0064] FIG. 7 describes a method in accordance with one or more embodiments. One or more steps described relative to FIG. 7 may be repeated and / or omitted. Further, the steps may be performed in a different order without departing from the scope of the disclosure.

[0065] In step 700, a flow of crude oil 100a is received in a crude oil feed 200. In some embodiments, the flow of crude oil 100a may be raw crude oil. The raw crude oil may be extracted from a hydrocarbon reservoir located below ground using a well. In other embodiments, the flow of crude oil 100a may include treated crude oil. In some embodiments, the crude oil feed 200 may be part of a GOSP.

[0066] In step 705, a steam recovery system 245 receives a first flow of LP steam 225b. In some embodiments, the steam recovery system 245 is disposed along a steam feed 230 within the GOSP. Further, in some embodiments, the first flow of LP steam 225b is produced by a second heat exchanger 205b, c disposed along the crude oil feed 200. To produce the first flow of LP steam 225b, the second heat exchanger 205b, c may receive a second flow of LP steam 225a (produced from the steam generation system 260) and the flow of crude oil 100a.

[0067] In step 710, the steam recovery system 245 produces a first flow of condensed steam 250a from the first flow of LP steam 225b.

[0068] In step 715, a first heat exchanger 400a-c receives the flow of crude oil 100a and the first flow of condensed steam 250a. The first heat exchanger 400a-c may be disposed along the crude oil feed 200.

[0069] In step 720, the first heat exchanger 400a-c produces a first flow of treated crude oil 100a from the flow of crude oil 100a using the first flow of condensed steam 250a. In other words, heat within the first flow of condensed steam 250a is exchanged with the flow of crude oil 100a to produce a flow of heated crude oil 100a. In some embodiments, the first heat exchanger 400a-c further produces a second flow of condensed steam 250b. Accordingly, the second flow of condensed steam 250b may be cooler than the first flow of condensed steam 250a. In these embodiments, the second flow of condensed steam 250b may be received by the steam generation system 260. In some embodiments, the steam generation system 260 may be disposed along the steam feed 230.

[0070] In some embodiments, a flash drum 235 disposed along the crude oil feed 200 may receive the flow of treated crude oil 100a and produce a flow of dry crude oil 100b and / or flow of gas 105b. In these embodiments, a second heat exchanger 205a disposed along the crude oil feed 200 may receive the flow of dry crude oil 100b and use the flow of dry crude oil 100b to produce a flow of crude oil 100a that is heated.

[0071] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the below claims.EXAMPLES

[0072] Hereinafter, projections of how the disclosed systems may operate within a GOSP in the future are provided as compared to how the conventional GOSP operations described relative to FIG. 2 may operate. The projections are determined by simulating the conventional GOSP operations and disclosed system. Hereinafter, the disclosed system described relative to FIG. 4 is denoted “configuration 1” or “C1,” the disclosed system described relative to FIG. 5 is denoted “configuration 2” or “C2,” and the disclosed system described relative to FIG. 6 is denoted “configuration 3” or “C3.”

[0073] Table 1 provides projections of GOSP-related metrics associated with the conventional GOSP operations as described in FIG. 2 (denoted “B” in Table 1) relative to C1, C2, and C3. The projections are provided for the years 2035 and 2051. In these examples, the second heat exchanger 205b is a trim heat exchanger, the second heat exchanger 205c is a flash drum heat exchanger, and the first pump 220 is a crude charge pump. Assumptions include that the flow of crude oil 100a is at least 150° F. prior to reaching the trim heat exchanger, that the flow of dry crude oil 100b meets various export standards, such as the temperature of the flow of dry crude oil 100b being between 178° F. to 191° F.TABLE 1Year20352051MetricUnitsBC1C2C3BC1C2C3SteamMMBtu / hr025.242.4081.681.8CondensateHeater PowerTemperature° F.11712392102into LPDTGas fromMillion13.414.913.315.5LPDTstandardcubic feetper day(MMSCFD)TrimMMBtu / hr115.293.186.4352.3289.2276.3ExchangerPowerTrimklb / hr126101.994.5385.4316.4302.2ExchangerSteamDemandFlash Drum° F.148157148165HeatExchangerInletTemperatureFlash Drum° F.178177191186HeatExchangerOutletTemperatureFlash DrumMMBtu / hr70.467.754.9102.289.363.2HeatExchangerPowerFlash Drumklb / hr77.174.160.1111.897.769.1HeatExchangerSteamDemandGas fromMMSCFD14.312.420.318Flash DrumGas toMMSCFD27.727.333.633.4AtmosphericCompressorAtmosphericHp3238318739023859CompressorPowerCrude ChargeHp1583179715831797Pump PowerReduction inMMBtu / hr24.776Heat DemandReduction inKlb / hr27.183.1SteamDemandReduction inHp—−238−74−74—−246−74−74PowerRequirementTotal EnergyMegawatt—7.068.394.49—22.122.211.37Savings(MW)

[0074] Table 2 provides projections of GOSP-related metrics associated with C1, C2, and C3 relative to costs and CO2 emissions. Note maintenance costs are considered every 5 years.TABLE 2CO2CO2InitiativeEmissionsEmissionsNetChange -Change -OverallCapExPresentfrom fuelfromCO2DifferenceValuegaselectricityEmissionsMillions(NPV)consumptionproductionChangeC($MM)$MMKilotonsKilotonsKilotons15.93−3.32−4373.72−43326.20−0.36−6891.15−68836.37−3.68−3341.15−332

[0075] Tables 1 and 2 show that the disclosed system may be technically and economically viable.

Examples

examples

[0072]Hereinafter, projections of how the disclosed systems may operate within a GOSP in the future are provided as compared to how the conventional GOSP operations described relative to FIG. 2 may operate. The projections are determined by simulating the conventional GOSP operations and disclosed system. Hereinafter, the disclosed system described relative to FIG. 4 is denoted “configuration 1” or “C1,” the disclosed system described relative to FIG. 5 is denoted “configuration 2” or “C2,” and the disclosed system described relative to FIG. 6 is denoted “configuration 3” or “C3.”

[0073]Table 1 provides projections of GOSP-related metrics associated with the conventional GOSP operations as described in FIG. 2 (denoted “B” in Table 1) relative to C1, C2, and C3. The projections are provided for the years 2035 and 2051. In these examples, the second heat exchanger 205b is a trim heat exchanger, the second heat exchanger 205c is a flash drum heat exchanger, and the first pump 220 is a c...

Claims

1. A system comprising:a crude oil feed configured to receive a flow of crude oil;a steam recovery system configured to receive a first flow of low-pressure steam and produce a first flow of condensed steam; anda first heat exchanger disposed along the crude oil feed,wherein the first heat exchanger is configured to receive the flow of crude oil and the first flow of condensed steam, andwherein the first heat exchanger is further configured to produce, using the first flow of condensed steam, a first flow of treated crude oil from the flow of crude oil.

2. The system of claim 1, wherein the first heat exchanger is further configured to produce a second flow of condensed steam.

3. The system of claim 2, further comprising a steam generation system configured to receive the second flow of condensed steam.

4. The system of claim 3, wherein the steam generation system is further configured to produce a second flow of low-pressure steam from the second flow of condensed steam.

5. The system of claim 4, further comprising a second heat exchanger disposed along the crude oil feed,wherein the second heat exchanger is configured to receive the flow of crude oil.

6. The system of claim 5, wherein the second heat exchanger is further configured to receive a flow of dry crude oil.

7. The system of claim 6, wherein the second heat exchanger is further configured to produce, using the flow of dry crude oil:a second flow of treated crude oil from the flow of crude oil; anda flow of stable crude oil.

8. The system of claim 5, further comprising a flash drum disposed along the crude oil feed and configured to produce the flow of dry crude oil from the flow of treated crude oil.

9. The system of claim 4, further comprising a second heat exchanger disposed along the crude oil feed,wherein the second heat exchanger is configured to receive the flow of crude oil and the second flow of low-pressure steam.

10. The system of claim 8, wherein the second heat exchanger is further configured to produce, using the second flow of low-pressure steam:a second flow of treated crude oil from the flow of crude oil; andthe first flow of low-pressure steam.

11. A method comprising:receiving, in a crude oil feed, a flow of crude oil;receiving, by a steam recovery system, a first flow of low-pressure steam;producing, from the steam recovery system, a first flow of condensed steam from the first flow of low-pressure steam;receiving, by a first heat exchanger, the flow of crude oil and the first flow of condensed steam; andproducing, from the first heat exchanger using the first flow of condensed steam, a first flow of treated crude oil from the flow of crude oil.

12. The method of claim 11, further comprising producing, from the first heat exchanger using the first flow of condensed steam, a second flow of condensed steam.

13. The method of claim 11, further comprising receiving, by a second heat exchanger, a second flow of low-pressure steam and the flow of crude oil.

14. The method of claim 13, further comprising producing, from the second heat exchanger using the second flow of low-pressure steam:a second flow of treated crude oil from the flow of crude oil; andthe first flow of low-pressure steam.

15. The method of claim 13, further comprising producing, from a steam generation system, the second flow of low-pressure steam.

16. The method of claim 12, further comprising receiving, by a steam generation system, the second flow of condensed steam.

17. The method of claim 11, further comprising receiving, by a second heat exchanger, a flow of dry crude oil and the flow of crude oil.

18. The method of claim 17, further comprising producing, from the second heat exchanger using the flow of dry crude oil:the flow of treated crude oil from the flow of crude oil; anda flow of stable crude oil.

19. The method of claim 17, further comprising receiving, by a flash drum, the flow of treated crude oil.

20. The method of claim 19, further comprising producing, from the flash drum, the flow of dry crude oil.

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