ZERO METHANE OIL AND GAS PRODUCTION FACILITY DESIGN

Abstract

Presented herein is a facility design for oil production with zero methane emissions. The facility is flexible to allow variable flow rate requirements through the production cycle of the facility. Equipment is modular and easily movable, which reduces upfront construction cost, time to production revenue, the need for steel on facility, and other long-term material resource requirements. The design reduces emission of greenhouse gases, environmental impacts and landowner lease requirements.

Claims

1. A method of producing oil and gas at a facility during an initial period of production and a secondary period of production, comprising: receiving fluid flow to a separator; using the separator to produce gas, produced water and oil from the fluid; supplying the gas to an outlet module; supplying produced water to a first horizontal methane recovery vessel; supplying oil to a second horizontal methane recovery vessel; capturing vented gas from the first horizontal methane recovery vessel and the second horizontal methane recovery vessel using a vent line; and supplying vented gas from the first horizontal methane recovery vessel and the second horizontal methane recovery vessel through the vent line to a vapor recovery unit.

2. The method of claim 1, wherein the first horizontal methane recovery vessel and the second horizontal methane recovery vessel are mounted on skids.

3. The method of claim 1, further comprising: supplying gas from the vapor recovery unit to the outlet module.

4. The method of claim 1, further comprising: establishing a laminar flow of fluid having a Reynold's number less than approximately 2000 from the separator to the first horizontal methane recovery vessel and the second horizontal methane recovery vessel.

5. The method of claim 1, further comprising: supplying the gas to a boiler; incinerating the gas to generate heat; and using the heat to generate electricity.

6. The method of claim 5, further comprising: powering the vapor recovery unit using the generated electricity.

7. The method of claim 6, wherein the generated electricity is direct current.

8. The method of claim 1, further comprising; supplying oil to a third horizontal methane recovery vessel during the initial period of production for the facility; and removing the third horizontal methane recovery vessel from the facility during the secondary period of production.

9. The method of claim 1, further comprising: supplying vented gas from the first horizontal methane recovery vessel and the second horizontal methane recovery vessel through the vent line to a second vapor recovery unit during the initial period of production for the facility; and removing the second vapor recovery unit from the facility during the secondary period of production.

10. The method of claim 1, further comprising: supplying oil to at least six horizontal methane recovery vessels during the initial period of production for the facility.

11. The method of claim 10, further comprising: supplying vented gas from the at least six horizontal methane recovery vessels to at least four vapor recovery units during the initial period of production for the facility.

12. The method of claim 1, further comprising: maintaining a pressure of at least 3 pounds per square inch in the first horizontal methane recovery vessel.

13. The method of claim 1, further comprising: providing a pipe assembly including a plurality of pipe modules; positioning a first plurality of horizontal methane recovery vessels on a first side of the pipe assembly; positioning a second plurality of horizontal methane recovery vessels on a second side of the pipe assembly, opposite the first side; connecting the first plurality of horizontal methane recovery vessels and the second plurality of methane recovery vessels to the pipe assembly during the initial period of production for the facility; and removing at least one of the first plurality of horizontal methane recovery vessels, at least one of the second plurality of horizontal methane recovery vessels and at least one of the plurality of pipe modules during the secondary period of production for the facility.

14. The method of claim 13, wherein the pipe assembly is mounted on a skid.

15. A vapor recovery system in an oil and gas production facility, comprising: a horizontal methane recovery vessel including a vent; a vapor recovery unit connected to vent; and an outlet assembly coupled to the vapor recovery unit.

16. The vapor recovery system of claim 15, wherein the horizontal methane recovery vessel includes a cylindrical body with a ratio of horizontal length to diameter greater than 2:1.

17. The vapor recovery system of claim 15, wherein the horizontal methane recovery vessel includes a cylindrical body with a ratio of horizontal length to diameter greater than 3:1.

18. The vapor recovery system of claim 15, wherein the horizontal methane recovery vessel includes a cylindrical body with a ratio of horizontal length to diameter greater than 4:1.

19. The vapor recovery system of claim 15, wherein the horizontal methane recovery vessels includes a cylindrical body with a ratio of horizontal length to diameter of approximately 5:1.

20. The vapor recovery system of claim 15, further comprising a vent line assembly including a venting outlet, the venting outlet including a pressure control valve.

21. The vapor recovery system of claim 20, wherein the pressure control valve has a set point of at least 10 pounds per square inch.

22. The vapor recovery system of claim 20, wherein the vent line assembly further includes a generator outlet, the generator outlet connected to a thermoelectric generator.

23. The vapor recovery system of claim 15, wherein the horizontal methane recovery vessel and vapor recovery unit are connected to a common support structure.

24. The vapor recovery system of claim 15, wherein the vapor recovery unit includes a direct current motor.

25. An oil and gas production facility, comprising: at least one separator; a plurality of horizontal methane recovery vessels fluidly connected to the at least one separator, each horizontal methane recovery vessel including a vent; and a plurality of vapor recovery units, each vapor recovery unit connected to the vent of a respective horizontal methane recovery vessel.

26. The oil and gas production facility of claim 25, wherein each of the plurality of horizontal methane recovery vessels are mounted to skids.

27. The oil and gas production facility of claim 25, further comprising a venting assembly that includes a branch pipe connected to the vent of each of the plurality of horizontal methane recovery vessels, at least two of the plurality of horizontal methane recovery vessels are positioned on a first side of the branch pipe and at least two of the plurality of horizontal methane recovery vessels are positioned on a second side of the branch pipe, opposite the first side.

28. The oil and gas production facility of claim 25, further comprising a plurality of separators, each separator fluidly connected with a pipe module assembly, wherein at least two of the plurality of separators are positioned on a first side of the pipe module assembly and at least two of the plurality of separators are positioned on a second side of the pipe module assembly, opposite the first side.

29. The oil and gas production facility of claim 25, further comprising an electronic control valve fluidly connected between the separator and the plurality of methane recovery vessels.

30. The oil and gas production facility of claim 25, further comprising a thermoelectric generator.

31. The oil and gas production facility of claim 25, further comprising a venting outlet, the venting outlet including a pressure control valve.

32. The oil and gas production facility of claim 25, wherein at least one of the plurality of horizontal methane recovery vessels stores produced water and at least one of the plurality of horizontal methane recovery vessels stores oil.

33. The oil and gas production facility of claim 25, wherein each of the plurality of horizontal methane recovery vessels includes a cylindrical body defining a ratio of horizontal length to diameter in a range of approximately 2:1 to 5:1.

34. The oil and gas production facility of claim 25, further comprising a high pressure separator and a low pressure separator, the high pressure separator mounted above the low pressure separator.

35. The oil and gas production facility of claim 25, wherein the at least one separator, the plurality of horizontal methane recovery vessels and the plurality of vapor recovery units are mounted on a skid.

36. A carbon offset credit issuance method for a carbon measurement system, comprising: generating real-time internal telemetry data of flow of fluid within a system; generating real-time external telemetry data of release of emissions from the system; communicating the internal and external telemetry data to a computing system; and generating a digital representation of a carbon offset credit using a carbon offset credit issuance algorithm based on the internal and external telemetry data.

37. The method of claim 36, wherein the digital representation of the carbon offset credit is manifested and issued through a fungible token on a blockchain.

38. The method of claim 36, wherein the digital representation of the carbon offset credit is manifested and issued through a non-fungible token on a blockchain.

39. The method of claim 36, further comprising wirelessly communicating internal and external telemetry data throughout the carbon measurement system.

40. The method of claim 36, wherein power to obtain internal and external telemetry data and generate the digital representation is provided through locally generated thermoelectric energy.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0004] FIG. 1 is a schematic flow diagram of an oil and gas production system.

[0005] FIG. 2 is a schematic layout of an oil and gas production facility during an initial period of production.

[0006] FIG. 3 is a schematic layout of an oil and gas production facility during a secondary period of production.

[0007] FIG. 4 is an isometric view of an HP/LP separator assembly.

[0008] FIG. 5 is a side view of the HP/LP separator assembly of FIG. 4.

[0009] FIG. 6 is an end view of the HP/LP separator assembly of FIG. 4.

[0010] FIG. 7 is an isometric view of an HP separator assembly.

[0011] FIG. 8 is a plan view of the HP separator assembly of FIG. 7.

[0012] FIG. 9 is an end view of the HP separator assembly of FIG. 7.

[0013] FIG. 10 is a side view of the HP separator assembly of FIG. 7.

[0014] FIG. 11 is an isometric view of an LP separator assembly.

[0015] FIG. 12 is a plan view of the LP separator assembly of FIG. 11.

[0016] FIG. 13 is an end view of the LP separator assembly of FIG. 11.

[0017] FIG. 14 is a side view of the LP separator assembly of FIG. 11.

[0018] FIG. 15 is a plan view of a pipe module for use in connecting to a plurality of separators.

[0019] FIG. 16 is an end view of the pipe module of FIG. 15.

[0020] FIG. 17 is an isometric view of two separators connected with a pipe module.

[0021] FIG. 18 is a plan view of a layout of a plurality of separators connected with a plurality of pipe modules.

[0022] FIG. 19 is a side view of a methane recovery vessel assembly.

[0023] FIG. 20 is a plan view of the methane recovery vessel assembly of FIG. 19.

[0024] FIG. 21 is a front-end view of the methane recovery vessel assembly of FIG. 19.

[0025] FIG. 22 is a rear-end view of the methane recovery vessel assembly of FIG. 19.

[0026] FIG. 23 is an isometric view of the methane recovery vessel assembly of FIG. 19.

[0027] FIG. 24 is another isometric view of the methane recovery vessel assembly of FIG. 19.

[0028] FIG. 25 is a detailed view of a portion of the methane recovery vessel assembly of FIG. 19.

[0029] FIG. 26 is a plan view of a pipe module for use in connecting to a plurality of methane recovery vessel assemblies.

[0030] FIG. 27 is an end view of the pipe module of FIG. 26.

[0031] FIG. 28 is an isometric view of two methane recovery vessel assemblies connected with a pipe module.

[0032] FIG. 29 is a plan view of a layout of a plurality of methane recovery vessel assemblies connected with a plurality of pipe modules.

[0033] FIG. 30 is an end view of the layout of FIG. 29.

[0034] FIG. 31 is a detailed end view of a portion of the layout of FIG. 29.

DESCRIPTION

[0035] FIG. 1 is a schematic flow diagram of an oil and gas processing facility method or process 100. Inlet liquid to the process 100 is provided through initial flow lines 102 to supply one or more high-pressure (HP) separators 104 that separate HP gas from liquid. HP gas is sent along line 106 to an output line 108. In the embodiment illustrated, line 106 includes a branch 106a from a first separator, a branch 106b from a second separator and a main branch line 106c connected to the branches 106a, 106b. Main branch line 106c connects to outlet line 108. In further embodiments, any number of separators can be utilized, each separator including a branch connecting to line 106c. Meters (e.g., meter 162 schematically illustrated) can be connected to each of the branches to provide an indication of volume of gas produced from each separator 104. Liquid from HP separator 104 is sent through a dump line 110 to one or more low-pressure (LP) separators 112. Meters (e.g., meter 160 schematically illustrated) can be connected to the dump line 110 to provide an indication of volume of liquid produced from each separator 104. In one embodiment, both the HP separators 104 and the LP separators 112 are oriented horizontally, having a length that is longer than the height. In another embodiment, either the HP separators 104 or the LP separators 112 can be oriented vertically.

[0036] As illustrated herein, the LP separators 112 are three-phase separators that separate LP gas, oil, and produced water. LP gas is sent from the LP separators 112 along line 114 to an outlet line 116. In an alternative embodiment, a compressor 118 compresses LP gas in line 114 and sends pressurized gas to line 106. Valves and meters can be connected to inlet sides and outlet sides of the separators 104 and 112 to control flow therethrough. For example, meters (e.g., meter 168 schematically illustrated) can be connected to line 114 to provide an indication of volume of gas produced from each separator 112. In one embodiment, the valves are controlled with electric actuators and assist in establishing a laminar flow through the lines of the process 100. Laminar flow is useful in creating a consistent volume of flash gas for capture vs venting or flaring resulting from a more traditional slug flow regime. In one embodiment, the laminar flow includes a Reynold's number of 2000 or less.

[0037] Oil from LP separators 112 is sent or supplied along line 120, whereas produced water from LP separators 112 is sent along line 122. Meters (e.g., meters 164 and 166 schematically illustrated) can be connected to each of the lines 120 and 122, respectively, to provide an indication of volume of fluid produced from each separator 112. Line 120 leads to one or more oil methane recovery vessels 124 and line 122 leads to one or more produced water methane recovery vessels 126. Oil can be unloaded from oil methane recovery vessels 124 through a line 128 (e.g., to a truck or connected pipeline). Produced water can be unloaded from produced water methane recovery vessels 126 through a line 130 (e.g., to a truck or connected pipeline). In one embodiment, pressure of oil and produced water unloaded through lines 128 and 130 is at least three (3) pounds per square inch. In other embodiments, pressure through lines 128 and 130 is in a range of three to twelve (3-12) pounds per square inch.

[0038] Oil methane recovery vessels 124 and produced water methane recovery vessels 126, in one embodiment, are oriented horizontally (i.e., having a major axis extending along a length of the vessel and a minor axis extending along a height of the vessel, a maximum dimension of the vessel along the major axis being greater than the maximum dimension of the vessel along the minor axis). A vent line 132 is connected to oil methane recovery vessels 124 and produced water methane recovery vessels 126 to carry vented gas to one or more thermoelectric generators 134, one or more vapor recovery units (VRU) 136, and a flare outlet 138. As illustrated herein, vent line 132 includes branches 132a and 132b carrying gas from oil methane recovery vessels 124 and produced water methane recovery vessels 126, respectively. Branches 132a and 132b are connected to a main vent line 132c, which carries vented gas to a generator outlet 132d, a recovery outlet 132e and a flare outlet 132f. In an alternative embodiment, the thermoelectric generator 134 is not required. As illustrated in FIG. 1, VRUs 136 can be positioned upstream of main vent line 132c (as illustrated in phantom lines), or the VRUs 136 can be positioned downstream of main vent line 132c, for example the VRUs can be positioned to receive vapor from flare outlet 132e. In one embodiment, one VRU 136 is provided for each methane recovery vessel and located proximate its respective methane recovery vessel. In other embodiments, one or more VRUs 136 are positioned together to receive vapor from a common line.

[0039] Enclosure of the methane recovery vessels 124, 126 using vent line 132 creates enclosed, pressurized vessels that limit oxygen from entering. Pressure within the vessels can be maintained at a level of three (3) pounds per square inch or greater. In one embodiment, the pressure within the vessels is maintained at a level of approximately ten to twelve (10-12) pounds per square inch. By limiting or preventing oxygen from entering vessels 124, 126, or vent line 132, there is a lower likelihood of an emission event because of gas rejection at a delivery point due to a gas composition specification, a lower likelihood of creating an explosive gas mixture, or corrosive environment. Additionally, a separate vapor recovery tower installed in current facilities can be eliminated. Pressure in vent line 132 can be maintained at desired levels to provide sufficient pressure to VRUs 136. Operation of VRUs 136 can be enhanced with sufficient pressure (e.g., between three to eight (3-8) pounds per square inch) being provided thereto. Moreover, when pressure is not to a desired level, VRUs 136 can be turned off.

[0040] Methane recovery vessels 124 and 126 functions in part like an integrated vapor recovery tower (VRT) and atmospheric tank (which are commonly deployed in oil and gas production facilities today. Due to laminar process flow of fluids throughout process 100, pressure levels throughout the flow are more balanced, and an upper surface area of stored fluids to volume ratio is orders of magnitude higher than current vapor recovery towers, creating a significantly more favorable flash gas environment to capture methane. For example, current vapor recovery towers are 30 to 40 feet tall with a diameter of two to three feet, which equates to roughly 7 square feet of flash surface area versus two methane recovery vessels at approximately 800 square feet. In the initial production period of a facility where more methane recovery vessels are present, the surface area is increased by roughly 400 square feet for each methane recovery vessel. Further, the pressure at the top of the 30 to 40 feet VRT is roughly 10 pounds which is dumping into an atmospheric tank at 4 ounces of pressure, requiring venting or flaring of gas to prevent catastrophic consequences.

[0041] Along vent line 132, gas sent to the thermoelectric generators 134 is provided to a boiler 140 that incinerates the gas, thereby creating heat. Thermoelectric generators 134 generate electricity from the generated heat. This electricity can then be used to power VRUs 136 and other components such as control valves and transducers. In other embodiments, VRUs 136 and other components can be powered by other means, such as grid connected power, diesel or other types of generators, wind power, solar power and others.

[0042] In one embodiment, VRUs 136 can include a variable speed direct current (DC) motor. A DC motor can provide higher starting torque, faster starting and stopping, variable speeds with voltage input and more efficient control than corresponding alternating current (AC) motors. In one embodiment, the DC motor is a brushless motor. The DC motor can allow for a smaller form factor of VRU 136, for example allowing a form factor that is co-located with a corresponding methane recovery vessel (e.g., attached to a common support structure). Various compressors can operate VRU 136, such as reciprocating compressors, oil-flooded screw compressors, rotary sliding vane and other mechanism providing positive displacement. In combination with pressurized methane recovery vessels 124 and 126, utilizing a DC motor with the VRUs 136 enables all or substantially all flash gas (i.e., spontaneous vapor produced during transport and/or depressurization of fluid) within process 100 to be captured, even when flow of fluid throughout process 100 is not in a steady state. In contrast, current oil and gas production facilities are unable to capture some flash gas incidents and as such release methane to atmosphere through a vent or flaring. In one embodiment, gas along line 106 can be sent along a secondary line 142 to thermoelectric generator 134 to generate electricity as desired. In another embodiment, gas sent to the VRUs 136 is compressed, scrubbed, and provided along a line 144 to either the thermoelectric generator 134, outlet line 116, and/or compressor 118. In instances where pressure along 144 exceeds a regulator pressure to the thermoelectric generator 134 or VRU 136, gas can be sent to flare outlet 138 through line 144b at pressure for example 12-15 pounds per square inch.

[0043] In the embodiment illustrated, lines 128 and 130 can further be equipped with corresponding vapor block mechanisms 150 and 152, respectively. Vapor block mechanisms 150 and 152 can be used to prevent vapors from exiting the bottom of methane recovery vessels 124 and 126, respectively, for example, when gas or produced water are being removed from the methane recovery vessels 124 and 126.

[0044] In the embodiment illustrated, meters 156-196 provide internal metrics of volume throughout process 100. Zero-methane emissions verification can be achieved through internal or direct meter telemetry (i.e., sensors directly measuring volume of fluids flowing through process 100) and continuous external or indirect emissions monitoring captured through distributed sensors 154 (herein illustrated as six sensors, although any number of sensors can be used). The external or indirect sensors 154 can measure any rogue gases, or any emissions vented or flared through outlet 138. Example sensors can include a forward looking infrared (FLIR) camera that indicates emission from one or more components of the process 100.

[0045] Voluntary reporting, policy-driven compliance, and carbon offset certification are evolving at a rapid rate geographically. Carbon offset credit issuance for a carbon reduction system can be achieved based on the measured flow versus the current carbon offset calculation estimates. Credits can include geographic certification based on a measured carbon offset credit algorithm (e.g., based on calculations from sensors 156-196). The carbon offset credit algorithm can be run in real-time (e.g., in an actual time during which a process or event occurs) also incorporate meter and external sensor telemetry from existing oil and gas production facilities that utilize current designs including vapor recovery towers, atmospheric stock tanks, and pneumatic control valves. In one embodiment, a computing system 198 (e.g., ultra-low power) captures the meter and sensor telemetry, processes the telemetry data through a carbon offset credit algorithm, and issues a digital representation of a carbon offset credit. In one embodiment, the digital representation of the carbon offset credit is manifested and issued through a fungible token on a distributed ledger (e.g., a blockchain) or a centralized database. In another embodiment, the digital representation is manifested and issued through a non-fungible token on a blockchain. In one embodiment, system 198 maintains a continuous internet connection for token, blockchain, control, wireless, telemetry, and management communication. In an additional embodiment, power to operate computing system 198 is provided from thermoelectric generators 226.

[0046] FIG. 2 is a schematic diagram of an example layout of an oil and gas production facility layout 200 that implements oil and gas process 100. Layout 200 is used during an initial production period for a facility. The initial production period requires an increased amount of production equipment to handle a higher flowing pressure and rate of fluid from connected wells. Production equipment within layout 200 is modular in nature, allowing equipment to be removed after the initial production period and repurposed elsewhere. For example, some or all of the production equipment (e.g., pipe rack assemblies, separator assemblies, vessel assemblies, VRU assemblies) within layout 200 can be mounted to a skid or support structure that can easily be transported by a fork lift, crane and a truck to be positioned in a desired location. Upon initial set up of layout 200, production equipment is delivered by truck to a well site. The production equipment can be offloaded from the truck and positioned as desired, for example in the layout 200. Once wellhead pressure reduces a need for certain pieces of production equipment, the equipment can be loaded onto a truck (e.g., using a crane or fork lift) and removed from the layout 200. In contrast to current oil production facility layouts that construct concrete pads, vertical storage tanks and other production equipment on site, most or all of the production equipment in layout 200 can be produced offsite and transported to an oil well site. Once used, the production equipment can be removed and leave little trace at the site.

[0047] In the illustrated embodiment, layout 200 includes a plurality of flow lines 202 (herein illustrated as six flow lines, although any number of flow lines can be used) that carry fluid from one or more oil wells. The layout 200 further includes a plurality of HP/LP separator assemblies 204. Each of the plurality of flow lines 202 connects to a respective HP/LP separator assembly 204. HP/LP separator assemblies 204 are arranged on either side of a pipe rack assembly (e.g., a branch pipe assembly) 206. As illustrated herein, there are three HP/LP separator assemblies 204 on a first side of pipe rack assembly 206 and three HP/LP separator assemblies 204 on a second side of pipe rack assembly 206. In the illustrated embodiment, pipe rack assembly 206 is formed of a plurality of connected separator pipe modules, denoted A, which will be discussed in more detail below.

[0048] Pipe rack assembly 206 is connected to an adjacent pipe rack assembly 208 (e.g., a main pipe assembly), which includes a first trunk assembly module 210 (denoted F), a plurality of connection assembly trunk modules 212 (each denoted C), and a second trunk assembly module 214 (denoted E). First trunk assembly module 210, in one embodiment, includes an HP gas outlet 216 and an LP gas outlet 218. Pipe rack assembly 208 is connected to a pipe rack assembly 220 (e.g., a branch pipe assembly) that extends between a plurality of methane recovery vessel assemblies 222. Pipe rack assembly 220 is formed of a plurality of individual pipe modules (each denoted B). The methane recovery vessel assemblies 222 are arranged on either side of the pipe rack assembly 220 and can store oil or produced water. Pipe rack assembly 208 is further connected to a plurality of vapor recovery units 224 through second trunk assembly module 214. Vapor recovery units 224 process vapor from the vessel assemblies 222 using a compressor, scrubber, motor, and switching device. In one embodiment, the vapor recovery units 224 each include a DC motor. Although illustrated together in a separate structure, in another embodiment, VRUs 224 can be directly co-located with individual vessels 222, which feed into the pic rack assembly 220.

[0049] Layout 200 also includes a plurality of thermoelectric generators 226, a battery bank 228 and, a flare module 230. Thermoelectric generators 226, in one embodiment, include a boiler used to incinerate gas provided thereto. The heat generated from the incineration is used to generate electricity, which can be used to power various components (e.g., control valves, meters, VRUs, communication elements) of the layout 200. Excess power that is generated by thermoelectric generators 226 can be stored within battery bank 228 for later use. Flare module 230 connects to pipe rack assembly 208 and is configured to provide emergency flare gas relief during an upset condition. In other embodiments, power to production equipment for layout 200 is provided via grid power, solar power, wind power and/or via a generator.

[0050] Once available wellhead pressure of an oil and gas well has reduced and/or the volume of produced fluids entering the flow lines 202 has naturally declined, some of the equipment from layout 200 can be removed (e.g, via truck) and used elsewhere. As illustrated in FIG. 3, a reduced layout 300 is illustrated. HP separators have been removed from HP/LP separator assemblies, leaving LP separator assemblies 302. In addition, some of vessel assemblies 222 have been removed, as have some of vapor recovery units 224 and thermoelectric generators 226. In one embodiment, as will be discussed below, some or all of the equipment in layout 200 can be mounted to a frame, platform or skid for more efficient transportation, installation, and removal. FIGS. 4-31 described below are example embodiments of the equipment discussed in FIGS. 2 and 3. As discussed below, the equipment can be mounted to a suitable support structure such as a frame or skid. The support structure allows for production equipment to be moved on-site (e.g., using a crane or fork lift) as well as to and from sites (e.g., using a truck).

[0051] FIGS. 4-6 illustrate several views of an example HP/LP stacked separator assembly 400. Assembly 400 includes an HP separator assembly 402 mounted above an LP separator assembly 404. HP separator assembly 402 includes a separator 410 mounted to a frame or skid 412. Similarly, LP separator assembly 404 includes a separator 414 mounted to a frame or skid 416. A vertical support frame 418 is mounted to skid 416 and supports skid 412 above skid 416 such that skid 412 is located above separator 414. HP/LP separator assembly 400 fluidly connects to an inlet flow line 420 and produces fluids to a plurality of outlets 422. In one embodiment the HP/LP separator assembly 404 is stacked to create a more universal installation by allowing all interconnect piping to match up regardless of location topography, slope, and reduces the length of interconnect piping.

[0052] FIGS. 7-10 illustrate several views of the HP separator assembly 402. Separator 410 receives high-pressure gas from an inlet 430 and produced fluids to a gas outlet 432, a cleanout port 434, a high-pressure drain 436, and a high-pressure dump 438. A gas meter 440 measures the volume of high-pressure gas passing therethrough and provides a digital readout of the volume.

[0053] FIG. 11-14 illustrate several views of the LP separator assembly 404. Separator 414 receives the fluid stream from either the HP dump 438 or well stream inlet 450 and separates low-pressure gas to a gas outlet 452, oil to an oil outlet 454, and produced water to a produced water outlet 456. A gas meter 458 measures the volume of low-pressure gas passing therethrough and provides a digital readout indicative of the volume. An oil meter 460 and produced water meter 462 measures the volume of oil and produced water, respectively, therethrough and each produces a digital readout indicative of the volume.

[0054] FIGS. 15 and 16 illustrate views of a pipe rack assembly 500 used to connect to outlets of HP/LP separator assembly 400. Pipe rack assembly 500 can be connected to adjacent rack assemblies that further carry fluids therethrough. Pipe rack assembly 500 includes a frame or skid that supports inlet pipes on either side to connect with the HP/LP separator assembly 400, including oil inlet pipes 502a and 502b, HP gas inlet pipes 504a and 504b, produced water inlet pipes 506a and 506b, and LP gas inlet pipes 508a and 508b. The inlet pipes connect with corresponding outlet pipes, including an oil outlet pipe 502c, an HP gas outlet pipe 504c, a produced water outlet pipe 506c, and an LP gas outlet pipe 508c. Pipe rack assembly 500 further includes a cable tray 510 configured to carry cables. FIG. 17 illustrates an arrangement where a first separator assembly 400a and a second separator assembly 400b are positioned on opposite sides of pipe rack assembly 500. FIG. 18 illustrates an arrangement where a first column of separators (400a, 400c, and 400e) are positioned on a first side of a column of pipe modules (500a, 500b, and 500c) and a second column of separators (400b, 400d, and 400f) are positioned on a second side of the column of pipe modules (500a, 500b, and 500c).

[0055] FIGS. 19-25 illustrate several views of a methane recovery vessel assembly 600, including a methane recovery vessel 602 mounted to a skid or frame 604. The methane recovery vessel 602 design and construction allows for higher operating pressure within the vessel 602 (e.g., at a target of 2-5 pounds per square inch, 6-10 pounds per square inch, 11-15 pounds per square inch vs. operating pressure in vertical tanks of 3-12 ounces of pressure). The vessel design also allows a vent to capture vapors to eliminate methane emissions. In the illustrated embodiment, the vessel 602 has a cylindrical body having a length (i.e., along a major axis of the body) greater than a diameter of the body. A ratio of length to diameter of the cylindrical body can be selected as desired. In various embodiments, the ratio can be 2:1, 3:1, 4:1, 5:1 or greater than 5:1, or any ratio in between. In one specific embodiment, the length of the cylindrical body is 480 inches and the diameter of the cylindrical body is 96 inches, which equals a length to diameter ratio of 5:1.

[0056] A plurality of vertical supports 606 extends from skid 604 to support either side of vessel 602. Fluid (e.g., oil, produced water) is provided to methane recovery vessel 602 through an inlet 608 connected through a piping assembly 610. Connected to vessel 602 include a pressure relief valve 612, top cleanout 614, level sensor 616 (e.g., a guided wave radar sensor), temperature indicator transmitter 618, and a pressure indicator transmitter 620. Temperature indicator transmitter 618 can be connected to a temperature indicator 622, and pressure indicator transmitter 620 can be connected to a pressure indicator 624. In addition, a level switch 626 can be connected to vessel 602 and provide a signal based on a level of fluid within vessel 602. The level switch 626 can be activated in situations where the level of fluid within vessel 602 exceeds the desired level, enabling safer conditions.

[0057] Vessel 602 further includes a bottom cleanout 630, a vent 632 connected to a gas outlet pipe assembly 634, an oil outlet 636 connected to an oil outlet pipe assembly 638, and a produced water outlet 640 connected to a produced water outlet pipe assembly 642.

[0058] In an embodiment illustrated in FIG. 19, a VRU 644 is directly coupled to (e.g., mounted to, connected to, secured to) frame 604. Pipe assembly 634 extends and is fluidly connected with the VRU 644. VRU can then be fluidly coupled with a common gas outlet pipe assembly as discussed below.

[0059] The outlet pipe assemblies can be connected to a corresponding pipe module 700 as illustrated in FIGS. 26 and 27. Pipe module 700 includes a frame or skid as illustrated that supports a produced water inlet pipe 702, an oil inlet pipe 704, a produced water outlet pipe 706, and an oil outlet pipe 708. In addition, pipe module 700 further includes a gas outlet pipe 710. The produced water inlet pipe 702 and oil inlet pipe 704 can be connected to pipe assembly 610 through a tank inlet pipe 712. In addition, a produced water outlet pipe 714 can connect produced water outlet pipe 642 to the produced water outlet pipe 706. The oil outlet pipe 708 can be connected to oil outlet pipe 638 through an oil outlet pipe 716. Further still, a gas outlet pipe 718 can connect gas outlet pipe 634 to the gas outlet pipe 710. FIGS. 28-31 illustrate various views of methane recovery vessel assemblies 600 associated with corresponding pipe rack modules 700.

[0060] Concepts presented herein include a coordinated implementation of oil and gas production facility design and equipment combination that eliminates methane emissions by effectively capturing and processing methane throughout the facility and eliminating various fugitive emission points found in traditional oil and gas facilities. This design also reduces material resource waste (i.e., steel structures overbuilt for the long-term), and includes facility flexibility. Features presented herein include horizontal, modular methane recovery vessel assemblies rather than static vertical tanks that are purpose-built on-site. Electronic control valves are positioned throughout the facility rather than pneumatic control valves which require a methane release to operate. A connection to a power grid or other supplemental generator can be included to operate the electric components. Components such as control valves actuators and various facility monitoring devices can use radio communication such that wire material can be greatly reduced, seamless disconnect process of equipment, and characteristics of the facility can be analyzed, and control signals can be transmitted to enable remote operation of the facility. By operating the entire facility on DC power, a roughly 30% efficiency gain (reduction in demand) in the facility power requirements can be achieved.

[0061] In some embodiments, power can be provided by a thermoelectric power generator that utilizes heat off of a low-emissions burner to operate all electronic control valves, sensors, and communications across the facility. This generator replaces the need for a diesel or natural gas generator to provide remote power, as well as further emissions reduction. Typical diesel or natural gas generators are oversized (e.g., generating approximately 70 kilowatts (kW) to 100 kW), and do not operate with the reliability, efficiency desired or at the dramatically lower facility power requirements. By right-sizing the generator, and utilizing a proprietary thermoelectric generator, emissions are reduced further while reliability and longevity are increased.

[0062] The integrated assembly of these critical elements can achieve zero methane release (or significant reduction, if not all elements are utilized), reduced impact and resource requirements for long-term facility use (50% to 80% less equipment and footprint size of the facility after 24 months), reduced carbon dioxide emissions and improved yield in production (estimated 1%-2%) due to capture of methane and other emissions into the product stream.

[0063] When applied across hundreds or thousands of new oil facilities, concepts presented herein can reduce methane and rogue vapor emissions and dramatically reduce demand for new steel each year from the oil and gas industry. After 12-24 months of initial production, up to 80% of equipment on site can be shifted to a new location rapidly. This relocation would reduce steel demand over time as new production facilities apply this design. Per facility, this reduces the waste of materials and labor, lowers long-term steel requirements, and dramatically impacts the carbon emissions from its production, transport, and manufacturing.

[0064] When applied to a new facility, a fully modular and skid-mounted system can be implemented for all site operations. This arrangement is an efficient and low impact solution. Many well sites have abandoned 80% of their equipment within 24 months due to production decline, and often the rest is abandoned on site when the well ceases production of oil and gas. Some of the most common dangers in current industry design involve on-site welding, stick-built facilities out in the elements, and the maintenance of tall vertical storage tank facilities. With a fully modular and skid-mounted design as discussed herein, some fixed amount of easily deployable equipment could serve thousands or tens of thousands of wells for many decades with dramatically reduced impact, materials, and dangerous field labor. This design reduces regular working hazards, labor costs, and environmental impact, while increasing the longevity, usefulness, and efficiency of facilities design for the entire industry.

[0065] Various embodiments of the invention have been described above for purposes of illustrating the details thereof and to enable one of ordinary skill in the art to make and use the invention. The details and features of the disclosed embodiment are not intended to be limiting, as many variations and modifications will be readily apparent to those of skill in the art. Accordingly, the scope of the present disclosure is intended to be interpreted broadly and to include all variations and modifications coming within the scope and spirit of the appended claims and their legal equivalents.