GAS PRODUCTION INSTALLATION AND METHOD FOR PRODUCING A PRESSURIZED NATURAL GAS STREAM

Description

1 / 53 GAS PRODUCTION INSTALLATION AND METHOD FOR PRODUCING A PRESSURIZED NATURAL GAS STREAM

[001] Split from BR112023006021-4 deposited on 08 / 10 / 2021. CROSS-REFERENCE TO RELATED REQUESTS

[002] The present description claims priority to US Patent Application Serial Number 17 / 470,438, entitled Apparatus and method for harnessing energy from a wellbore to perform multiple functions while reducing emissions, filed September 9, 2021, and claims priority to and benefit of U.S. Patent Application Serial Number 63 / 089,777, entitled Separator for Gas Production Units, filed October 9, 2020, both of which are incorporated herein by reference. TECHNICAL FIELD

[003] The present invention relates to separators, gas production units and methods for separating gas from liquid, sand and debris being produced from oil and gas wells and more specifically to such devices used to facilitate the production of emission-free or nearly emission-free natural gas and energy for use in the production of LNG (liquefied natural gas), CNG (compressed natural gas), electricity, hydrogen and oxygen. BACKGROUND

[004] Modern natural gas and oil wells generate enormous pressure. In some cases, these pressures can reach 138,000 kPa (20,000 PSIG). Transporting natural gas through pipelines at these pressures is inconceivable, not only due to the enormous thickness the pipeline would have to have, but primarily because not all wells can produce at these pressures, specifically when they are depleted. In the United States, the general pressure at which transmission pipelines operate is approximately 6,900 kPa (1,000 PSIG) or even lower in the case of field collection systems. Pipelines, compressors, and processing equipment, and generally the industry as a whole, have adopted and targeted this standard pressure range of approximately 6,900 kPa (1,000 PSIG). Because of this, the proposal for modern natural gas and oil well production and return equipment is to employ designs that reliably separate and reduce wellhead gas pressure to pipeline pressure, approximately 6,900 kPa. Petition 870260078306, dated 05 / 08 / 2026, page 10 / 178 2 / 53 (1,000 PSIG) or less, and securely reduce the wellhead pressure to near atmospheric pressure so that the separated oil, water, and other sands or debris are placed in tanks on site.

[005] Conventional technology often uses a single valve, commonly a choke valve, to reduce the pressure of the entire wellhead outlet. This often requires heat to counteract the cooling effect, or more formerly the Jules Thompson (JT) effect, associated with the reduction in the pressure of the produced gas. In practical terms, energy in the form of natural gas flaring is used to neutralize the energy in the form of cooling associated with this pressure reduction (which, as noted, could be as high as 138,000 kPa (20,000 PSIG) down to pipeline pressures of 6,900 kPa (1,000 PSIG) or lower). Because natural gas is flared as part of this process, emissions are also generated.Furthermore, energy in the form of natural gas or electricity is consumed as the gas is transported through pipelines, and through multiple stages of compression, to central facilities where even more energy is needed to generate compressed natural gas (CNG), liquefied natural gas (LNG), and electricity that can be used to produce other byproducts such as hydrogen. The additional energy required to generate these products adds equipment, cost, and environmental footprint to their production.

[006] Many CNG plants, for example, obtain their natural gas from distribution pipelines operating below 690 kPa (100 PSIG). There are enormous inefficiencies and emissions associated with reducing the pressure of a well from 138,000 kPa (20,000 PSIG) to 6,900 kPa (1,000 PSIG), transporting the gas many kilometers, compressing it multiple times along the way, only to reduce the pressure to 690 kPa (100 PSIG) and then back to 24,840 kPa (3,600 psi), the usual CNG pressure. Similarly, LNG is typically generated in large central plants that use a huge amount of energy to cryogenically cool the gas, using the Jules Thompson effect, in order to liquefy the gas. Similar to the inefficiencies of CNG, there are enormous inefficiencies and carbon emissions associated with reducing the pressure of a well from 138,000 kPa (20,000 PSIG) to 6,900 kPa (1.000 PSIG), transporting the gas for many kilometers, compressing it multiple times along the way, to a central facility where more energy is consumed to generate a pressure drop. Petition 870260078306, dated 05 / 08 / 2026, page 11 / 178 3 / 53 in order to cryogenically cool the gas to liquefy it. In other words, to produce the well, energy is used to combat the Jules Thompson effect, energy is used to transport the gas to a central facility, and even more energy is used to employ the Jules Thompson effect to liquefy the gas.

[007] Many natural gas well sites utilize two primary devices to condition the gas and fluids produced from each well for delivery in the pipeline exiting the well site. The first of these devices, known in the art as gas production units (GPUs), removes liquids (such as water and / or oil) from the produced gas. The GPU also conditions the pressure of the gas and liquid exiting the well to be accepted by the pipeline or local tanks, in the case of liquids. Before the gas and liquid enter the GPU, the second device, a separate reservoir known as a sand separator, is employed. This device captures any sand or debris from the well in order to prevent damage to the operating components of the GPU.Controlling sand and debris is a critical element of well production, as the pressures and flow rates experienced by modern gas wells combined with the erosive and mechanical fouling effects of sand and debris can have catastrophic implications. A typical gas production installation including a sand separator 10 and a GPU 20 is shown in Figure 1. The GPU 20 is often equipped with a choke valve that reduces the gas and liquid pressure from, for example, approximately 34,500 kPa (5,000 psi) at the wellhead and sand separator 10 to approximately 9,660 kPa (1,400 psi) or below at the GPU 20 outlet. This pressure drop within the GPU creates a cooling effect that is mitigated by the gas and liquid moving through a set of coils before and after the choke valve. The coils may be submerged in glycol heated by a burner.

[008] Existing sand separators and GPUs have many disadvantages and limitations, including a large footprint, increased capital expenditure requirements for redundant vessels associated with the GPU and sand separator, manual dumping of sand and debris from the sand separator, unsophisticated and unreliable fluid level monitoring and control, unintelligent and unreliable valve modulation to remove fluid and sand from the system, limited process flow rates, reliance on third-party vendors for return operations, and significant labor and maintenance requirements. As a result of the lack of Petition 870260078306, dated 05 / 08 / 2026, page 12 / 178 4 / 53 reliability of current methods and lack of electrical feedback that the equipment is operating properly, a third container or polishing vessel has, in certain cases, been employed to capture any fluid not captured by the GPU.

[009] More specifically, existing sand separators 10 and GPUs 20 have limited flow capacities that cannot handle the initial fluid and sand volume exiting the wellbore. As such, temporary return equipment is employed to handle the initial fluid, sand, and debris from the wellbore before the permanent sand separator 10 and GPU 20 are used. Return equipment, or dispersers, are typically supplied by third-party vendors and add substantial cost and time to the production process.

[0010] Furthermore, existing sand separators 10 allow sand and debris to accumulate within the separator 10, which can cause obstruction when the sand is subsequently drained. Moreover, if the sand is not drained on a sufficiently frequent basis, the sand and debris are allowed to move into the GPU, damaging its components. Because well sand production is random and there are few ways to know the sand level in the sand separator, establishing a precise drainage frequency is not possible. As a result, and because of the damage that sand and debris cause to the GPU, significant manpower is required to manually empty the reservoir in a more frequent cycle than would otherwise be required.

[0011] Furthermore, existing devices experience erosion throughout the entire flow path. Due to the unreliable and imprecise nature of sand separation, the sand tends to move with the liquid and gas, damaging all equipment it encounters. By substantially removing all fluid, sand, and debris immediately downstream of the wellhead, the piping downstream of the separator is no longer subject to erosion. This reduces the cost of downstream piping by eliminating the need for additional pipe wall thickness (erosion clearance), damped tees and elbows, etc. It also reduces maintenance and the need to replace corroded piping.

[0012] Moreover, existing devices do not provide real-time feedback or precision control of the separation process. As a result, if a Petition 870260078306, dated 05 / 08 / 2026, page 13 / 178 5 / 53 If the GPU malfunctions and the fluid dump fails, water is allowed into the piping and eventually transmitted to the downstream compressor station. In this scenario, there is no way to know on which platform or which well on which platform the GPU is faulty. Furthermore, if a GPU malfunctions and the fluid dump stick opens, gas could escape into the fluid tanks on the well platform and ultimately into the atmosphere. SUMMARY

[0013] The embodiments of the present description are generally directed to a separator fluidly connected to an unrestricted wellbore. In some non-limiting embodiments, the separator includes a reservoir that defines an internal chamber. The reservoir is capable of operating at a pressure greater than the pressure of a fluid being produced from the unrestricted wellbore, the fluid including liquid, gas, sand, and debris. The separator further includes an inlet through which the fluid being produced from the unrestricted wellbore is directed into the reservoir. The separator further includes an outlet through which the gas is directed out of the reservoir at a pressure substantially equal to the pressure of the fluid being produced from the unrestricted wellbore. The separator further includes at least one liquid level sensor capable of detecting a liquid level within the internal chamber of the reservoir at the pressure of the fluid being produced from the unrestricted wellbore.The separator also includes an electronically controlled valve communicating with a lower portion of the reservoir. The separator further includes a controller connected to at least one liquid level sensor and the electronically controlled valve, the controller programmed to open, close, or modulate the electronically controlled valve to regulate the combined flow of liquid, sand, and debris out of the lower portion of the reservoir at least partially in response to the liquid level within the reservoir's inner chamber detected by at least one liquid level sensor.

[0014] In some non-limiting embodiments, the controller is programmed to open, close, and / or modulate the electronically controlled valve to maintain a predetermined liquid level within the inner chamber of the reservoir. Petition 870260078306, dated 05 / 08 / 2026, page 14 / 178 6 / 53

[0015] In some non-limiting embodiments, the separator further includes a fluid connection link to the inner chamber of the reservoir, in which at least one liquid level sensor is disposed within the link.

[0016] In some non-limiting embodiments, the reservoir also includes one or more fluid connection ports with the linkage to allow equalization of the fluid level between the linkage and the inner chamber of the reservoir.

[0017] In some non-limiting modalities, a lower portion of the ligament is oriented at an angle to the inner chamber of the reservoir.

[0018] In some non-limiting embodiments, an upper portion of the ligament is fluidly connected to the outlet piping at the top of the reservoir.

[0019] In some non-limiting embodiments, the separator further includes a drain line extending from the linkage to a location downstream of the electronically controlled valve, the drain line being coupled to a valve.

[0020] In some non-limiting embodiments, at least one liquid level sensor is disposed within the reservoir.

[0021] In some non-limiting embodiments, at least one liquid level sensor includes a guided wave radar sensor.

[0022] In some non-limiting embodiments, at least one liquid level sensor includes a differential pressure sensor.

[0023] In some non-limiting embodiments, the separator also includes at least one limit sensor to indicate whether the liquid level is above or below a predetermined set point within the inner chamber of the reservoir.

[0024] In some non-limiting embodiments, at least one limit sensor includes an upper limit sensor to indicate that the liquid level is above a predetermined high point within the inner chamber.

[0025] In some non-limiting embodiments, at least one limit sensor includes a lower limit sensor to indicate that the liquid level is below a predetermined low point within the inner chamber.

[0026] In some non-limiting embodiments, the separator also includes a first density sensor to indicate the density of the fluid inside the chamber. Petition 870260078306, dated 05 / 08 / 2026, page 15 / 178 7 / 53 internal to the reservoir, and a second density sensor located downstream of the electronically controlled valve to indicate a flow rate and / or density of the fluid emitted from the reservoir.

[0027] In some non-limiting embodiments, the separator also includes a pressure sensor to indicate the fluid pressure downstream of the electronically controlled valve.

[0028] In some non-limiting embodiments, the controller is programmed to operate and provide feedback to an operator in or substantially in near real time.

[0029] In some non-limiting embodiments, the electronically controlled valve includes a discharge valve.

[0030] In some non-limiting embodiments, the flush valve is configured to be selectively operated in a manual mode and / or the controller is programmed to allow the flush valve to operate in a fixed position.

[0031] In some non-limiting embodiments, the separator further includes an ESD valve connected downstream of the discharge valve, wherein the ESD valve is connected to the controller and electronically controlled to close under certain conditions.

[0032] In some non-limiting embodiments, the separator also includes a filter arranged upstream of the discharge valve to remove larger debris particles but allow sand and smaller debris particles to pass through the discharge valve.

[0033] In some non-limiting embodiments, the inlet includes a tube extending into the inner chamber of the reservoir with one terminal end of the tube being partially obstructed by a baffle adapted to direct the incoming fluid to the bottom of the inner chamber.

[0034] In some non-limiting embodiments, the separator further includes a diffuser disposed within the inner chamber of the reservoir, the diffuser adapted to generally direct the gas upwards and direct the sand and debris downwards within the reservoir. Petition 870260078306, dated 05 / 08 / 2026, p. 16 / 178 8 / 53

[0035] In some non-limiting embodiments, the separator also includes a shut-off valve in fluid communication with, and upstream of, the inlet and electronically connected to the controller, the controller being programmed to open, close and / or modulate the shut-off valve to control the flow of fluid produced from the wellbore being directed into the reservoir.

[0036] In some non-limiting configurations, the outlet is located at the top of the reservoir.

[0037] In some non-limiting embodiments, the separator also includes a valve position sensor to indicate an operating position of the electronically controlled valve, the valve position sensor connected to the controller to provide feedback of the operating position of the electronically controlled valve to the controller.

[0038] In some non-limiting embodiments, the separator further includes a second electronically controlled valve downstream of the outlet, a bypass flow line extending from the outlet to a location downstream of the second electronically controlled valve, and a bypass valve in the bypass flow line to selectively control the flow of gas through the bypass flow line.

[0039] Other embodiments of the present description are directed to a gas production facility. In some non-limiting embodiments, the gas production facility includes a separator comprising a reservoir that defines an inner chamber. The reservoir is designed to operate at a pressure greater than the pressure of a fluid being produced from an unrestricted wellbore, the fluid including liquid, gas, sand and debris. The separator further includes an inlet through which the fluid being produced from the wellbore is directed into the reservoir. The separator further includes an outlet through which the gas is directed out of the reservoir at a pressure substantially equal to the pressure of the fluid being produced from the unrestricted wellbore. The separator further includes at least one liquid level sensor adapted to detect the liquid level within the inner chamber of the reservoir at the pressure of the fluid being produced from the unrestricted wellbore.The separator also includes an electronically controlled valve communicating with the fluid in a lower portion of the reservoir. The separator also includes a controller connected to at least one liquid level sensor and the valve. Petition 870260078306, dated 05 / 08 / 2026, page 17 / 178 9 / 53 electronically controlled, the controller programmed to open, close, or modulate the electronically controlled valve to regulate the combined flow of liquid, sand, and debris out of the lower portion of the reservoir in response to a liquid level within the reservoir's inner chamber detected by at least one liquid level sensor. The gas production installation also includes a line heater to heat the gas as it exits the separator, and a throttle to reduce gas pressure as it exits the line heater.

[0040] In some non-limiting embodiments, the gas production installation includes a separator unit comprising two separators as described above, the two separators being arranged close to each other and connected in series or in parallel.

[0041] In some non-limiting embodiments, each of the separators is connected to a separate wellhead and a separate choke downstream of the separate wellhead and wherein both separators are connected to the line heater.

[0042] In some non-limiting embodiments, the gas production facility also includes a sand reservoir located downstream of the electronically controlled valve to separate sand from the liquid stream, sand and debris.

[0043] In some non-limiting embodiments, the gas production installation also includes an injector drum separator located downstream of the electronically controlled valve to separate oil and water.

[0044] Other embodiments of the present description are directed to a separator fluidly connected to a wellbore. The separator includes a reservoir that defines an internal chamber. The separator further includes an inlet to supply the fluid being produced from a wellbore into the reservoir at an initial pressure, the fluid including liquid, sand, gas, and debris. The separator further includes an outlet through which the gas is directed out of the reservoir at a pressure substantially equal to the initial pressure. The separator further includes at least one liquid level sensor capable of detecting the liquid level within the internal chamber of the reservoir. The separator further includes an electronically controlled valve in fluid communication with a lower portion of the reservoir. The separator further includes a controller connected to at least one level sensor. Petition 870260078306, dated 05 / 08 / 2026, p. 18 / 178 10 / 53 of liquid and in the electronically controlled valve and programmed to open, close, or modulate the electronically controlled valve to regulate the combined flow of liquid, sand, and debris out of the lower portion of the reservoir at least partially in response to a liquid level within the inner chamber of the reservoir detected by at least one liquid level sensor.

[0045] In some non-limiting embodiments, the first pressure is an unregulated pressure of the fluid flowing from the wellbore.

[0046] In some non-limiting embodiments, the initial pressure is regulated by means of a pressure control valve between the wellbore and the separator.

[0047] In some non-limiting modes, the first pressure is at least 10,350 kPa (1,500 psi).

[0048] Other embodiments of the present description are directed to a method for producing a pressurized natural gas stream from a fluid being produced from a wellbore, the fluid including liquid, gas, sand, and debris. The method includes directing the fluid into a separator at a pressure substantially equal to the pressure of the fluid being produced from the wellbore. The method further includes directing the gas out of the separator at a pressure substantially equal to the wellbore pressure. The method further includes controlling the liquid level within the separator between two predetermined set points by regulating the flow of liquid, sand, and other solid debris out of a lower portion of the separator and / or regulating the gas flow rate out of the separator.

[0049] In some non-limiting embodiments, the method also includes regulating the flow of fluid being produced from the wellbore into the separator.

[0050] In some non-limiting embodiments, the method further includes maintaining either (a) a predetermined level of liquid within the separator by opening, closing, and / or modulating an electronically controlled valve connected to a controller in fluid communication with the separator to regulate the combined flow of liquid, sand, and debris from the lower portion of the separator, or (b) a predetermined fixed flow rate of liquid, sand, and debris passing through the electronically controlled valve. Petition 870260078306, dated 05 / 08 / 2026, page 19 / 178 11 / 53

[0051] In some non-limiting embodiments, the method also includes providing, through the controller, at least substantially real-time feedback to an operator on the liquid level within the separator.

[0052] In some non-limiting embodiments, the method further includes determining the liquid level within the separator using a liquid level sensor electronically connected to the controller, and opening, closing, and / or modulating the electronically controlled valve using the electronic controller to regulate the combined flow of liquid, sand, and debris from the lower portion of the separator and thereby maintain the predetermined liquid level.

[0053] In some non-limiting embodiments, the method further includes determining whether the liquid level is above or below a predetermined set point within the separator, initiating the flow of liquid, sand, and debris out of the lower portion of the separator if the liquid level is above the predetermined set point, and ceasing the combined flow of liquid, sand, and debris out of the lower portion of the separator if the set point is below the predetermined set point.

[0054] In some non-limiting embodiments, the method also includes conveying the gas from the separator to a line heater and throttling.

[0055] In some non-limiting embodiments, the method also includes closing the electronically controlled valve where the pressure or density of the combined flow of liquid, sand and debris from the lower portion of the separator reaches a certain predetermined value or if the electronically controlled valve has experienced erosion.

[0056] Other embodiments of the present description are directed to a system that includes a separator which includes an inlet to supply the fluid being produced from a wellbore into the separator at a first pressure, the fluid including liquid, gas, sand and debris. The separator further includes an outlet to supply the gas separated from the liquid, sand and debris out of the separator at substantially the same pressure. The system further includes a molecular dryer connected to the outlet of the separator, the molecular dryer having an outlet through which the gas substantially removed of water vapor is directed out of the molecular dryer at a second pressure which is substantially the same as the first pressure. The system further includes a turboexpander connected to the outlet of the dryer. Petition 870260078306, dated 05 / 08 / 2026, page 20 / 178 12 / 53 molecular, the turboexpander being powered by the pressure of gas directed out of the molecular dryer and generating both electricity and a substantially reduced temperature gas removed from water vapor of the gas being directed out of the molecular dryer.

[0057] In some non-limiting embodiments, the system described herein harnesses energy that has historically been wasted to generate CNG, LNG and electricity, and through electrolysis, hydrogen and oxygen, using turboexpanders and, as optionally explained below, also a hydroelectric turbine. These embodiments utilize the gas to produce these additional products in an emission-free or nearly emission-free manner.

[0058] In some non-limiting embodiments, the separator further includes a reservoir that defines an inner chamber, an electronically controlled valve in fluid communication with a lower portion of the reservoir, and a controller connected to the electronically controlled valve and programmed to open, close, or modulate the electronically controlled valve to regulate the flow of liquid, sand, and debris out of the lower portion of the reservoir in response to a detected liquid level within the inner chamber of the reservoir.

[0059] In some non-limiting embodiments, the system also includes a compressed natural gas filling station connected to the molecular dryer outlet or a second molecular dryer outlet to supply naturally compressed natural gas.

[0060] In some non-limiting embodiments, the system also includes a pressure control valve disposed between the compressed natural gas filling station and the molecular dryer to reduce the pressure of the gas being directed out of the molecular dryer from the second pressure to a third pressure, wherein the third pressure is lower than the second pressure.

[0061] In some non-limiting embodiments, the system further includes a compressed natural gas filling station connected to an outlet of the turboexpander, the turboexpander connected between the compressed natural gas filling station and the molecular dryer to generate mechanical energy as the gas being directed out of the molecular dryer is reduced from the second pressure to a third pressure, wherein the third pressure is lower than the second. Petition 870260078306, dated 05 / 08 / 2026, page 21 / 178 13 / 53 pressure, for the subsequent production of additional end products from the gas being directed out of the molecular dryer.

[0062] In some non-limiting embodiments, the system also includes a pressure control valve disposed between the molecular dryer outlet and the turboexpander to reduce the pressure of the gas being directed out of the molecular dryer from the second pressure to a third pressure, wherein the third pressure is lower than the second pressure.

[0063] In some non-limiting embodiments, the system also includes a second turboexpander disposed between the molecular dryer outlet and the turboexpander to reduce the pressure of the gas being directed out of the molecular dryer from the second pressure to a third pressure, wherein the third pressure is lower than the second pressure.

[0064] In some non-limiting embodiments, the system also includes a gas pipeline that supplies natural gas to a natural gas network connected to at least one of the molecular dryer or turboexpander.

[0065] In some non-limiting embodiments, the gas pipeline is connected to the molecular dryer and a pressure control valve is connected between the gas pipeline and the molecular dryer to reduce the pressure of the gas being directed out of the molecular dryer from the second pressure to a third pressure, wherein the third pressure is lower than the second pressure and substantially equal to a pipeline pressure at which the natural gas network supplies gas to a receiver.

[0066] In some non-limiting embodiments, the turboexpander is connected between the gas pipeline and the molecular dryer to reduce the pressure of the gas being directed through the turboexpander to a third pressure, wherein the third pressure is lower than the second pressure and substantially equal to a pipeline pressure at which the natural gas network supplies gas to a receiver.

[0067] In some non-limiting embodiments, the system further includes a cold box connected to one of the molecular dryers and the turboexpander, the cold box cryogenically cooling the gas exiting one of the molecular dryers and the turboexpander in order to produce liquid natural gas at a third pressure, wherein the third pressure is lower than the second pressure. Petition 870260078306, dated 05 / 08 / 2026, page 22 / 178 14 / 53

[0068] In some non-limiting embodiments, the turboexpander includes a cooling fluid outlet through which the reduced temperature gas generated by the operation of the turboexpander is directed out of the turboexpander, wherein the cold box is connected to the cooling fluid outlet to receive the reduced temperature gas to cryogenically cool the gas exiting the molecular dryer and the turboexpander.

[0069] In some non-limiting embodiments, the turboexpander produces energy, which is used for local energy consumption and / or to supply energy to an electrical power grid.

[0070] In some non-limiting embodiments, the turboexpander generates energy, which is used in an electrolysis process to separate water into hydrogen and oxygen.

[0071] In some non-limiting embodiments, the hydrogen and oxygen produced from the electrolysis process are fed into the cold box, and the cold box liquefies the hydrogen and oxygen.

[0072] In some non-limiting embodiments, the hydrogen and oxygen fed into the cold box are further fed into an auxiliary cooler to produce either liquid hydrogen or liquid oxygen.

[0073] In some non-limiting embodiments, the auxiliary cooler cools the oxygen to approximately -182.77°C (-297°F) and cools the hydrogen to approximately -252.77°C (-423°F).

[0074] In some non-limiting embodiments, the system also includes a compressor into which hydrogen is fed, which compresses the hydrogen for subsequent transport via truck or pipeline.

[0075] In some non-limiting embodiments, the turboexpander is connected to a gas compressor.

[0076] In some non-limiting embodiments, the separator includes a second outlet through which liquid, sand and debris are supplied out of the separator, the system further including a mechanism for removing solids from the liquid, sand and debris being supplied out of the separator and a hydroelectric turbine. Petition 870260078306, dated 05 / 08 / 2026, page 23 / 178 15 / 53 connected to the mechanism for removing solids, the hydroelectric turbine being adapted to generate electricity from the resulting liquid that exits the mechanism for removing solids.

[0077] In some non-limiting embodiments, at least one pressure control valve and / or turboexpander is disposed between the molecular dryer and the compressed natural gas filling station to reduce the pressure of the gas separated from the liquid, sand and debris supplied out of the separator from the second pressure to a third pressure, which is lower than the second pressure, wherein the pressure differential between the second pressure and the third pressure is used to generate mechanical energy and / or a cooling effect.

[0078] In some non-limiting embodiments, the system also includes a cold box connected to an outlet of the pressure control valve and / or turbo expander and which is supplied with the cooling effect.

[0079] In some non-limiting embodiments, the system also includes at least one pressure control valve and / or a turboexpander, disposed between the compressed natural gas filling station and a pipeline connection, to reduce the gas pressure from the third pressure to a fourth pressure, which is lower than the third pressure, wherein the pressure differential between the third and fourth pressures is used to generate mechanical energy and / or a cooling effect.

[0080] In some non-limiting embodiments, the system also includes a cold box connected to an outlet of the pressure control valve and / or turboexpander located between the compressed natural gas filling station and the pipeline connection and which is supplied with the cooling effect.

[0081] In some non-limiting embodiments, the system also includes at least one pressure control valve and / or a turbo expander disposed between the piping connection and a cold box to reduce the pressure from the fourth pressure to a fifth pressure, which is lower than the fourth pressure, wherein the pressure differential between the fourth pressure and the fifth pressure is used to generate mechanical energy and / or a cooling effect.

[0082] Other embodiments of the present description are directed to a gas production installation that includes a tree connected to a wellbore, a Petition 870260078306, dated 05 / 08 / 2026, page 24 / 178 16 / 53 A gas production tree including at least one first outlet, a second outlet, and one or more valves configured to control the flow of fluid produced from a wellbore. The gas production installation further includes a separator. The separator includes an inlet to supply fluid into the separator at a first pressure, the fluid including liquid, gas, sand, and debris, and an outlet to supply gas and / or a reduced volume of liquid, sand, and debris out of the separator at a pressure substantially equal to the first pressure. The gas production installation further includes a first flow path connecting the first outlet of the tree to the inlet of the separator. The gas production installation further includes a gas production unit that includes at least one control valve to reduce, restrict, and / or stop the flow of a gas or fluid flowing through it.The gas production facility also includes a second flow path that connects the second outlet of the tree to the gas production unit. The gas production facility also includes a third flow path that connects the separator outlet to the gas production unit or to the second flow path.

[0083] In some non-limiting embodiments, the gas production installation also includes a valve located along the third flow path.

[0084] In some non-limiting embodiments, the separator includes a reservoir that defines an inner chamber, an electronically controlled valve in fluid communication with a lower portion of the reservoir, and a controller connected to the electronically controlled valve and programmed to open, close, and / or modulate the electronically controlled valve to regulate the flow of liquid, sand, and debris out of the lower portion of the reservoir in response to a detected liquid level within the inner chamber of the reservoir.

[0085] In some non-limiting embodiments, the gas production installation also includes a scrap collector or filter located between the tank and the electronically controlled valve, and a collector located downstream of the electronically controlled valve.

[0086] In some non-limiting embodiments, the collector is connected to an outlet of the gas production unit through which liquid, sand, and / or debris are directed out of the gas production unit. Petition 870260078306, dated 05 / 08 / 2026, page 25 / 178 17 / 53

[0087] In some non-limiting embodiments, the gas production installation includes a second separator connected in parallel with the separator on a skid, wherein the second separator is fluidly connected to a second tree connected to a second wellbore.

[0088] Other embodiments of the present description are directed to a method for utilizing the energy associated with a high-pressure fluid that includes gas, liquid, sand, and debris being produced from a wellbore. The method includes separating the gas from the liquid, sand, and debris. The method further includes substantially removing water vapor from the gas. The method further includes passing the gas through a turboexpander, as the gas passes through the turboexpander the gas pressure dropping from a first pressure to a second pressure, wherein the second pressure is lower than the first pressure. The method further includes generating mechanical energy and a cooling effect from the pressure drop of the gas passing through the turboexpander.

[0089] These and other aspects and characteristics of a separator, an installation including a separator, and a process for operating a separator will become more apparent when considering the following description and the appended claims with reference to the accompanying drawings, all of which form a part of this specification, wherein equal reference numbers designate corresponding parts in the various figures. It should be expressly understood, however, that the drawings are for the purpose of illustration and description only and are not intended as a definition of the limits of the description. As used in the specification and claims, the singular forms a, an, and the include plural referents, unless the context clearly dictates otherwise. BRIEF DESCRIPTION OF THE DRAWINGS

[0090] For a fuller understanding of the present description and its features and advantages, reference is now made to the following description, taken together with the accompanying drawings, in which:

[0091] Figure 1 is a perspective view of a prior art gas production plant, which includes a conventional sand separator and a GPU;

[0092] Figure 2 is a perspective view of a separator according to an embodiment of the present description; Petition 870260078306, dated 05 / 08 / 2026, page 26 / 178 18 / 53

[0093] Figure 3 is a front view of the separator in Figure 2;

[0094] Figure 4 is a side view of the separator in Figure 2;

[0095] Figure 5 is a perspective view of the main body of the separator. Figure 2;

[0096] Figure 6 is a side cross-sectional view of the separator of Figure 2;

[0097] Figure 6A is a side cross-sectional view of a horizontal orientation of the separator in Figure 2.

[0098] Figure 7 is a detailed view of the entrance door of the separator of Figure 2;

[0099] Figure 7A is a detailed view of an alternative embodiment of an entry door of the separator of Figure 2;

[00100] Figure 8 is a fluid schematic of the separator in Figure 2;

[00101] Figure 9 is a fluid schematic of a double discharge valve arrangement for use with the separator of Figure 2;

[00102] Figure 10 is a schematic partial cross-sectional view of a separator according to another embodiment of the present description;

[00103] Figure 11 is a schematic partial cross-sectional view of a separator according to another embodiment of the present description;

[00104] Figure 12 is a schematic partial cross-sectional view of a separator according to another embodiment of the present description;

[00105] Figure 13 is a perspective view of a gas processing plant according to an embodiment of the present description;

[00106] Figure 14 is a rear view of the line heater and choke of Figure 13;

[00107] Figure 15 is a flowchart of a process for operating the separator in Figure 2;

[00108] Figure 16 is a cross-sectional view of the separator according to another embodiment of the present description; Petition 870260078306, dated 05 / 08 / 2026, page 27 / 178 19 / 53

[00109] Figure 17 is a schematic diagram illustrating a separator performing return operations according to an embodiment of the present description;

[00110] Figure 17A is a schematic diagram illustrating an embodiment employing double separators to perform return operations according to an embodiment of the present description;

[00111] Figure 18 is a schematic block diagram of a system according to an embodiment of the present description that uses a separator to provide a pressurized gas flow to various downstream components;

[00112] Figure 19 is a schematic block diagram of a system according to another embodiment of the present description that uses a separator to provide a pressurized gas flow to various downstream components;

[00113] Figure 20 is a schematic block diagram of a system according to yet another embodiment of the present description that uses a separator to provide a pressurized gas flow to various downstream components; and

[00114] Figure 21 is a schematic block diagram of a system according to yet another embodiment of the present description which uses two separators connected in series to provide a flow of pressurized gas to several downstream components. DETAILED DESCRIPTION

[00115] For the purposes of the description hereafter, the terms top, bottom, right, left, vertical, horizontal, top, bottom, side, longitudinal, and their derivatives shall refer to the description as it is oriented in the figures. However, it should be understood that the description may assume variations and alternative sequences of steps, except where expressly specified otherwise. It should also be understood that the specific devices and processes illustrated in the accompanying drawings and described in the following specification are simply exemplary aspects of the description. Therefore, the specific dimensions and other physical characteristics relating to the aspects described herein should not be considered limiting.

[00116] As used herein, the term psi means pounds per square inch. Petition 870260078306, dated 05 / 08 / 2026, page 28 / 178 20 / 53

[00117] As used herein, the term at least one of is synonymous with one or more of. For example, the sentence at least one of A, B, and C means any one of A, B, and C, or any combination of any two or more of A, B, and C. For example, at least one of A, B, and C includes one or more of A alone; or one or more of B alone; or one or more of C alone; or one or more of A and one or more of B; or one or more of A and one or more of C; or one or more of B and one or more of C; or one or more of all of A, B, and C. Similarly, as used herein, the term at least two of is synonymous with two or more of. For example, the sentence at least two of D, E, and F means any combination of any two or more of D, E, and F. For example, at least two of D, E, and F includes one or more of D and one or more of E; or one or more of D and one or more of F; or one or more of E and one or more of F; or one or more of all D, E, and F.

[00118] Referring to Figures 2-7, the embodiments of the present description are directed to a sand and liquid separator 1000 (hereinafter separator 1000) specifically adapted for use in natural gas wells. The main body 1100 of the separator 1000 is generally a hollow reservoir which defines an internal chamber 1010. In the embodiment shown in Figures 2-8, the main body 1100 is constructed of an upper reservoir section and a lower reservoir section, which together define a continuous internal chamber 1010. However, it should be understood that the main body 1100 could be constructed of any number of sections, including a continuous, unitary section as shown in Figures 10-12 and 16.The main body 1100 is preferably constructed of a strong, rigid material such as steel, designed, configured, or rated to operate at an inlet gas pressure flowing directly or indirectly (e.g., through a choke) from the wellbore. In some embodiments, the separator 1000 may be rated, designed, or configured to, or be capable of, operating at gas pressures greater than approximately 10,350 kPa (1,500 psi), or greater than approximately 17,250 kPa (2,500 psi), or greater than approximately 34,500 kPa (5,000 psi). In some embodiments, the separator 1000 may be rated, designed, or configured to, or be capable of, operating at gas pressures as high as or greater than an unregulated pressure at which gas flows from the wellbore. For example, the unregulated gas pressure at the wellhead of the Marcellus Shale formation wells can be approximately 34,500 kPa. Petition 870260078306, dated 05 / 08 / 2026, p. 29 / 178 21 / 53 (5,000 psi), and the unregulated gas pressure at the wellhead of Utica Shale formation wells may be approximately 69,000 kPa (10,000 psi). In other embodiments, the separator 1000 may be rated, designed, or configured to, or be capable of, operating at regulated gas pressures. For example, the gas pressure of a Utica Shale formation well may be regulated from approximately 69,000 kPa (10,000 psi) at the wellhead to approximately 34,500 kPa (5,000 psi) before being fed to the separator 1000. Such pressure regulation, which may be used to prevent damage or failure of the various components of the separator 1000 described herein, may be achieved by a choke or other device disposed in-line between the wellbore and the separator 1000.In some embodiments, the 1000 separator and its various components can be designed to meet various industry standards for pressure vessels or pressure and / or technical limitations associated with the instrumentation described herein. As those skilled in the art will appreciate, modifications to existing instruments and other system components (e.g., the 1100 main body of the 1000 separator) can be made to accommodate the high pressures of formations such as the Utica Shale formation without the need for equipment to regulate the pressure below that exiting the wellbore. As those skilled in the art will appreciate, the 1000 separator can be oriented horizontally instead of vertically, as shown in Figure 6A.

[00119] Furthermore, the described separator 1000 allows the separation of fluid, sand, and debris from the gas stream at available wellbore pressures, prior to gas pressure reduction. Maintaining the high gas pressure of the gas removed from the fluid, sand, and debris is advantageous, as this pressurized gas stream can be used for the production of compressed natural gas (CNG), liquefied natural gas (LNG), electricity, hydrogen, and / or oxygen. These products can be produced individually or simultaneously in any combination without compression and emission-free, with or without also supplying natural gas to a pipeline.

[00120] In embodiments where the main body 1100 is constructed of multiple sections, the various sections may be connected to each other using any suitable fastening method or device, such as mechanical fasteners (e.g., screws or rivets), a welded joint, or the like. The connection between the various sections must be sufficiently airtight to prevent the escape of gas. Petition 870260078306, dated 05 / 08 / 2026, page 30 / 178 22 / 53 high pressure and other materials from the inner chamber 1010 to the external environment. The main body 1100 can be supported in a generally vertical position by a structure 1002.

[00121] A plurality of inlets and outlets (e.g., in the form of ports and / or connecting flanges) may be provided in the main body 1100 to facilitate the flow of liquid, sand, and other debris through the separator 1000. An inlet (e.g., the inlet port 1020 provided in the main body 1100) may allow flow into the inner chamber 1010 of a wellbore. The inlet port 1020 may be fluidly connected to the wellbore by a rigid or flexible pipe, and the flow to the inlet port 1020 may be regulated by one or more valves or similar (see Figure 8). As shown in Figures 6-7, the inlet port 1020 may include a pipe 1022 extending into the inner chamber 1010, with one terminal end of the pipe 1022 being partially obstructed by a baffle 1024.The gas, liquid, sand, and other debris entering the inner chamber 1010 flow through the tube 1022, in the direction of arrow A, and any solid and / or liquid contaminants carried by the gas can be deflected by the deflector 1024 towards the bottom of the inner chamber 1010. Such contaminants may include, for example, sand, water, oil, rock, and metal fragments.

[00122] An outlet (e.g., a liquid, sand, and debris port 1030) may be provided in or near a lower portion of the inner chamber 1010. The outlet port 1030 may be fluidly connected to a valve 2000 which may be periodically and / or continuously opened and closed to drain liquid and solid contaminants collected at the bottom of the inner chamber 1010. The valve 2000 may be mounted remotely from the separator 1000 by a rigid or flexible tube. The valve 2000 may feed into a waste holding tank 3000 (see Figure 8), also via a rigid or flexible tube, to retain contaminants removed from the gas until the contaminants can be safely processed for disposal.

[00123] As shown in Figure 8, the holding tank 3000 can be fluidly coupled to one or more portions of downstream processing equipment 3002. The downstream processing equipment may include, for example, one or more separation components used to separate the different constituents of liquid, sand and / or debris emitted from the separator 1000. The equipment of Petition 870260078306, dated 05 / 08 / 2026, p. 31 / 178 23 / 53 Downstream processing 3002 may, in certain embodiments, comprise a dedicated sand reservoir configured to remove sand from the waste fluid, an injector drum type separator, or a pressurized four-phase separation skid (e.g., gas, sand, water, and oil) fitted with a sand removal device. The use of a pressurized four-phase separation skid may allow well pressure to provide the driving force to remove fluid from the well rig, instead of diesel transfer pumps.

[00124] Valve 2000 may be a discharge valve, and more specifically, a hardened discharge valve 2000. It should be noted, however, that any type of valve 2000 desired may be used to discharge liquid, sand, and / or debris from the lower portion of the inner chamber 1010. Valve 2000 may be a piston valve, a ball valve, a butterfly valve, a gate valve, a throttling valve, a needle valve, or similar suitable for operation at pressures up to, for example, 34,500 kPa (5,000 psi). Valve 2000 may include an electric, hydraulic, or pneumatic actuator, such as an electric motor, solenoid, hydraulic actuator, pneumatic actuator, or combinations thereof, so that the opening and closing of valve 2000 may be performed automatically by an electronic controller 4000 (see Figure 8). Therefore, the 2000 valve can be an electronically controlled valve.In certain embodiments, the 2000 valve may include a fast-acting, electrically driven linear valve actuator used to rapidly transition the 2000 valve between the open and closed positions and / or to one or more intermediate positions between the open and closed positions. The valve actuator may be capable of transitioning the 2000 valve between a fully open position and a fully closed position in less than 2.0 seconds, more specifically less than 1.0 second, or more specifically less than 0.5 seconds.

[00125] In some embodiments, the 2000 valve may be configured to be selectively operated in a manual mode. In some embodiments, the controller that controls the 2000 valve may be programmed to allow operation of the 2000 valve in a manual mode. Manual mode is a manual operating mode whereby the 2000 valve may be selectively opened or closed manually either by turning the handwheel handle or by the user pressing buttons on the valve to open and close it. This may allow equalization through the 2000 valve drain. Petition 870260078306, dated 05 / 08 / 2026, p. 32 / 178 24 / 53 is the line segment for valve maintenance. In some embodiments, the 2000 valve can be equipped with a bleed valve to perform maintenance on the 2000 valve.

[00126] In some embodiments, valve 2000 may be fitted with or coupled to a pressure pilot device configured to automatically initiate the closing of valve 2000 when encountering a pressure in the valve line above a predetermined limit. This can prevent high pressure from damaging the holding tank 3000 and / or other downstream components 3002, for example, in the event of gas passing through the liquid, sand and debris outlet 1030 of the separator 1000. The pressure pilot device associated with valve 2000 can thus provide fail-safe protection for the separator system. In other embodiments, a pressure transducer 4053 may be disposed in the valve line downstream of valve 2000 and configured to detect the pressure in the line and communicate the detected pressure to the controller 4000, as shown in Figure 8.The 4000 controller can then send an electronic command to close the 2000 valve to prevent high pressure from damaging downstream components. Either an active pilot safety valve or a pressure transducer can be used. Due to the critical nature of this operation, redundant pilot safety valves and / or pressure transmitters may be used.

[00127] As illustrated in Figure 8, in some embodiments, a valve position sensor 4050 may be disposed closer to or incorporated into valve 2000. The valve position sensor 4050 may include at least one visual sensing sensor, a motion sensor, a pressure sensor, a strain gauge, or any other type of sensor configured to indicate either a relative position of valve 2000 or simply whether valve 2000 is fully closed. The valve position sensor 4050 may indicate an operating position of valve 2000. The valve position sensor 4050 may be connected to the controller 4000 to provide feedback on the operating position of the electronically controlled valve 2000 to the controller 4000. This valve position feedback may be used by the controller 4000 to identify the presence of an obstruction in valve 2000 (for example, in the case that valve 2000 fails to close completely).When an obstruction is detected in valve 2000, controller 4000 can send a notification to a user interface 4002 connected to controller 4000. Petition 870260078306, dated 05 / 08 / 2026, page 33 / 178 25 / 53 mode that a user can manually remove the obstruction or switch the operation of valve 2000 to a backup valve. In other embodiments, the controller 4000 can issue a command to a piece of equipment designed to automatically remove obstructions from valve 2000. The obstruction can be cleared by initiating a rapid open / close cycle. In at least one embodiment, the feedback from the controller 4000 can be used to detect washout (erosion) where the valve is closed but fluid is still leaking beyond the valve. A second valve or emergency shutoff valve (ESD) 4057 may be located downstream of valve 2000.

[00128] In some embodiments, two or more 2000 valves may be provided in parallel with each other due to the critical nature of this component. If one of the two 2000 valves fails, leaks, erodes, or is inoperative (e.g., undergoing maintenance), the second 2000 valve may be used to operate the separator 1000. Figure 9 schematically illustrates the arrangement of two 2000A and 2000B valves in parallel. Primary valve 2000A and secondary valve 2000B can be identical valves, so fewer maintenance components and spare parts are needed to perform maintenance and repairs on valves 2000. As illustrated, valves 2000A and 2000B can be coupled to independent filters (or scrap collectors) 4110A and 4110B, respectively, provided upstream of valves 2000A and 2000B to capture debris.Valves 2000A and 2000B can feed the same waste holding tank 3000, as illustrated, or different waste holding tanks. Both valves 2000A and 2000B can be electronically controlled and connected to controller 4000. Valves 2000A and 2000B can be electronically controlled by controller 4000 to provide a fixed flow rate, for example, 150 barrels of water per hour, instead of being controlled to maintain a certain liquid level within the inner chamber 1010 of the reservoir. As those skilled in the art will appreciate, this method of operation can be employed, for example, where little or no gas is present.

[00129] Returning to Figures 2-8, in some embodiments, a plurality of connecting ports 1040a-1040d may be provided in the upper reservoir section 1100 and may be configured to connect to a connecting 1300. The connecting 1300 may include a tube 1310 and a plurality of connecting flanges 1320a. Petition 870260078306, dated 05 / 08 / 2026, p. 34 / 178 26 / 53 1320d. As illustrated, the 1310 pipe can be a vertical 1310 pipe (i.e., the geometric axis of the pipe is oriented vertically). Each of the 1320a-1320f connection flanges can connect to a corresponding 1040a-1040f connection port, so that fluid can flow freely between the 1310 pipe and any of the 1040a-1040f connection ports through the 1320a-1320f connection flanges. Since fluid can flow freely between the inner chamber 1010 and the linkage 1300 through the linkage ports 1040a-1040f, a fluid level inside the tube 1310 of the linkage 1300 self-equalizes with a fluid level inside the inner chamber 1010. As such, the fluid level inside the inner chamber 1010 can be verified by measuring the fluid level in the linkage 1300. The linkage 1300 also helps protect the instruments from gas bubbles inside the inner chamber 1010, which can cause the instruments to record inaccurate readings.

[00130] As shown in the accompanying drawings, a representative embodiment of the 1000 separator includes six 1040a-1040f connecting ports and six corresponding 1320a-1320f connecting flanges. As those skilled in the art will appreciate, the 1300 connecting port may include more than six connecting ports or a smaller number. The third connecting port from the top 1040c can correspond to a high liquid level within the inner chamber 1010, and the lowest connecting port 1040f can correspond to a low liquid level within the inner chamber 1010. During operation, the valve 2000 can be periodically and / or continuously opened and closed, or modulated between an open and closed position, to maintain the liquid level within the inner chamber 1010 at a desired level, for example, between the third connecting port from the top 1040c and the lowest connecting port 1040f.The two intermediate linkage ports 1040d, 1040e between the third linkage port from the top 1040c and the lowest linkage port 1040f can facilitate the equalization of the liquid level inside the inner chamber 1010 with the liquid level in the linkage 1300. The linkage port 1040a prevents the formation of a gas pocket at the top of the linkage 1300 and allows the liquid level sensor 1400 to make measurements along the entire length of the linkage 1300 and the reservoir. The linkage ports 1040a-f can be vertically spaced from each other and have sufficient cross-sectional area to ensure that the liquid level inside the linkage 1300 can quickly equalize with the liquid level inside the inner chamber 1010. That is, the linkage ports 1040a. Petition 870260078306, dated 05 / 08 / 2026, p. 35 / 178 27 / 53 f allow sufficient liquid flow into the linkage 1300 to minimize the time delay in equalizing the liquid level within the linkage 1300 with the liquid level within the inner chamber 1010. It should be understood that the separator 1000 may include more or fewer linkage ports, and a corresponding number of connection flanges, than are shown in the drawings in order to reduce the time for equalizing the liquid level in the linkage 1300. Furthermore, the linkage ports may have an increased cross-sectional area in order to reduce the time for equalizing the liquid level in the linkage 1300. The linkage 1300 may include a cleaning valve 1330 which may be used to evacuate sand or other particulate matter that may become trapped in the linkage 1300. The cleaning valve 1330 may be coupled to a drain line 1332 extending from the linkage 1300.In Figures 2-4, 6, and 6A, drain line 1332 is illustrated as leading back to the inner chamber 1010 of the separator. In other embodiments (e.g., as shown in Figure 8), drain line 1332 may be a flow path extending from the linkage 1300 to a downstream location of valve 2000 to discharge sand and other particulate matter to the waste holding tank 3000 or another downstream location.

[00131] In some embodiments, the drain line 1332 of the linkage 1300 may be at least partially inclined with respect to a vertical direction, as shown in Figure 10. In at least one instance, the drain line 1332 is installed at an angle of 45° to the vertical geometric axis of the linkage 1300. As shown in Figures 8 and 10, the lower drain line 1332 may be inclined back into the inner chamber 1010 of the separator 1000. The inclined drain line 1332 of the linkage 1300 may prevent the accumulation of sand or other particulate matter in the linkage 1300, since the inclined geometric axis of the drain line 1332 and its intersection with the inner chamber 1010 automatically forces any sand or particulate matter to settle at the bottom of the inner chamber 1010 for eventual discharge through the outlet 1030.

[00132] In some embodiments, the connection may be fitted with cleaning outlet ports or plugs, 1340a-1340f, as shown in Figure 6. These ports allow for cleaning of the equalization ports / piping in case sand or debris accumulates in the horizontal pipe segments associated with the equalization ports 1320a-f. Petition 870260078306, dated 05 / 08 / 2026, p. 36 / 178 28 / 53

[00133] A liquid level sensor 1400 can be inserted into the tube 1310 of the linkage 1300 to determine the liquid level inside the tube 1310 which, as noted above, is automatically equalized with the liquid level inside the inner chamber 1010, by the flow through the linkage ports 1040c, 1040d, 1040e, 1040f. The liquid level sensor 1400 may be in electronic communication with the controller 4000 which actuates the valve 2000. Specifically, the controller 4000 may open and close the valve 2000, and specifically modulate between open and closed states, based on the liquid level measured in the linkage 1300. In one embodiment, the liquid level sensor 1400 may be a guided wave radar sensor that includes a probe that extends generally parallel to a geometric axis of the tube 1310 so as to be immersed in any liquid within the linkage 1300.Examples of suitable, commercially available guided wave radar sensors include the Eclipse® Model 706 by Orion® Instruments. In other embodiments, the 1400 liquid level sensor may be a capillary tube, a differential pressure sensor, an ultrasonic sensor, or similar. However, guided wave radar may be desirable, as this technology can determine differences as fine as 2.54 mm (0.10 inches) of water column in real time and is effective throughout the life of the well up to, for example, 13.8 kPa (2 psi). Compared to a differential pressure sensor, guided wave radar may be desirable because it is not affected by the constantly changing gravity of the fluid. In some embodiments, the 1400 liquid level sensor may be configured to determine a stratification level between water and oil in the 1300 linkage.

[00134] In some embodiments, the separator 1000 may not include any linkage. For example, as shown in Figure 11, the separator 1000 may include a liquid level sensor 1400 inserted directly into an upper portion of an inner chamber 1010 of the separator 1000 to determine the liquid level within the separator 1000. The liquid level sensor 1400 may be a guided wave radar sensor, as described above. In still other embodiments, the separator 1000 may include either a linkage 1300 with a first liquid level sensor 1400 disposed therein (as shown in Figure 8) or a second liquid level sensor 1400 disposed within the inner chamber 1010 (as shown in Figure 11) to provide redundant measurements of the liquid level within the separator 1000. Petition 870260078306, dated 05 / 08 / 2026, page 37 / 178 29 / 53

[00135] With continuous reference to Figures 2-7, a gas outlet (e.g., a gas outlet port 1050) may be provided in the main body 1100 through which gas may flow out of the separator 1000 to downstream components of the installation, such as a line heater or molecular dryer. The gas outlet port 1050 may be fluidly connected to the downstream components, for example, by rigid or flexible tubing. The gas outlet port 1050 may be located vertically above the uppermost connecting port 1040a and therefore above the intended liquid level of the inner chamber 1010, so that no liquid flows out of the gas outlet port 1050 during normal operation. In some embodiments, a mist extractor 1052 may be provided within the inner chamber 1010 below the outlet port 1050 to prevent very fine water droplets / aerosols from reaching the outlet port 1050 and exiting the separator 1000.In some embodiments, a diffuser 1054 (see Figure 6) may be provided within the inner chamber 1010 to allow the gas to move more easily upwards within the inner chamber 1010.

[00136] In some embodiments, the gas outlet port 1050 may extend through a top of the main body 1100 of the separator 1000, as shown in Figures 2-7, thereby allowing a maximum linkage length 1300 and / or a maximum length between the upper and lower limits for the liquid level within the separator 1000. In other embodiments, as shown in Figure 12, the gas outlet port 1050 may extend through a side wall 1056 of the main body 1100 of the separator 1000.

[00137] In some embodiments, a gas measuring device 1057, as shown in Figure 8, may be installed to measure the gas volumes exiting the separator 1000. The measuring device may be an ultrasonic, orifice, VCone device, or any device capable of measuring gas volumes exiting the separator 1000. By measuring the gas flow immediately downstream of the separator 1000, gas from other wells that have been measured can be mixed. This is of particular importance where each of the wells is on different gas leases or has different gas owners. This also allows multiple wells to be interconnected to collectively harness their energy through common downstream equipment. Petition 870260078306, dated 05 / 08 / 2026, page 38 / 178 30 / 53

[00138] An upper sensor port 1060 may be provided in the main body 1100 of the separator 1000 and may receive an upper limit sensor 1064, such as a limit switch, a float switch, a thermal dispersion switch, or the like. The upper sensor port 1060 may be located vertically above the uppermost connection port 1040a and vertically below the gas outlet port 1050. In some embodiments, the upper limit sensor 1064 may be located above an uppermost point at which the liquid level sensor 1400 can detect liquid. The upper limit sensor 1064 may be used to detect the presence of liquid, and may thus serve as an auxiliary device, in addition to the liquid level sensor 1400, to determine whether the liquid level is above a predetermined high point within the inner chamber 1010.The upper limit sensor 1064 may be in electronic communication with the controller 4000, and the controller 4000 may be programmed or configured to initiate a shutdown procedure if liquid is detected by the upper limit sensor 1064.

[00139] Similarly, a lower sensor port 1064 may be provided in the main body 1100 of the separator 1000 and may receive a lower limit sensor 1066, such as a limit switch, a floating switch, a thermal dispersion switch, or the like. The lower sensor port 1062 may be located vertically below the lower connection port 1040f and vertically above the inlet port 1020. In some embodiments, the lower limit sensor 1066 may be located below the lowest point at which the liquid level sensor 1400 can detect the liquid. The lower limit sensor 1066 may be used to detect the presence of liquid, and may thus serve as an auxiliary device, in addition to the liquid level sensor 1400, to determine whether the liquid level is below a predetermined low point within the inner chamber 1010.Lower limit sensor 1066 may be in electronic communication with controller 4000, and controller 4000 may be programmed or configured to initiate a shutdown procedure if liquid is not detected by lower limit sensor 1066.

[00140] In the embodiments shown in Figures 2-6 and 8, the upper sensor port 1060 and the lower sensor port 1064 are provided in the main body 1100 of the separator 1000. Figure 16 shows an alternative embodiment in which the upper sensor port 1060 and the lower sensor port 1064 are provided in the linkage 1300. The functionality of the upper sensor port 1060 and the lower sensor port Petition 870260078306, dated 05 / 08 / 2026, page 39 / 178 31 / 53 1064, together with the associated upper and lower limit sensors 1064, 1066, is the same in the embodiment shown in Figures 2-6 and 8 and in the embodiment shown in Figure 16.

[00141] With reference to Figure 8, a density sensor port may be provided in the main body 1100 of the separator 1000 and may receive a density sensor 4052, such as a Coriolis meter or similar. The density sensor port may be located vertically above the lower sensor port 1064 and vertically below the lower linkage port 1040f. The density sensor 4052 may be used to detect the density or specific gravity of the fluid (liquid) within the main body 1100 of the separator 1000. The density sensor 4052 may be in electronic communication with the controller 4000, and the controller 4000 may be programmed or configured to open, close, or modulate a shut-off valve 4120 depending on the flow rate and / or concentration of sand detected in the liquid, sand, and debris within the separator 1000.

[00142] A second density sensor 4054 can be ported to the valve line upstream of valve 2000, as illustrated in Figure 8. The second density sensor 4054 can comprise the same type of sensor (e.g., a Coriolis meter) as the density sensor 4052 inside separator 1000. The second density sensor 4054 can be used to detect the flow rate and / or density or specific gravity of the fluid (liquid) in separator 1000. The density sensor 4054 can be in electronic communication with the controller 4000, and the controller 4000 can be programmed or configured to open, close, or modulate the shut-off valve 4120 depending on the flow rate and / or density or specific gravity of the fluid (liquid) inside separator 1000 (detected by sensor 4052) compared to the flow rate and / or concentration of sand, sand, and debris emitted from the liquid. separator 1000.By comparing the density measured by density sensor 4052 with the density measured by density sensor 4054, an accurate estimate of sand concentration can be determined, thus helping to understand in real time the density of fluid flowing through separator 1000. The determined density and the fluid flow rates through separator 1000 can be used to provide well production volume control. It can also serve as a safety device, shutting down the system if gas is present. Petition 870260078306, dated 05 / 08 / 2026, page 40 / 178 32 / 53

[00143] Referring again to Figures 2-6, a relief valve 1070 may be provided at or near the top of the upper reservoir section 1100 and may be configured to open at a predetermined pressure to allow pressurized gases to escape from the inner chamber 1010. The pressure at which the relief valve 1070 is configured to open may be selected to prevent damage to the separator 1000 and / or downstream components due to excess gas pressure. For example, the relief valve 1070 may be configured to open if the gas pressure within the inner chamber 1070 exceeds the maximum operating pressure of the separator 1000, for example, approximately 34,500 kPa (5,000 psi). The relief valve 1070 may be passive, for example having a spring that deflects at a predetermined burst pressure, or it may be actively controlled by the controller 4000.

[00144] With continued reference to Figures 2-6, the relative vertical locations of the various ports can optimize the performance of separator 1000. For example, inlet port 1020 can be located below the link ports 1040a-1040f, with deflector 1024 directing the influx downwards so that contaminants do not flow in that direction and become trapped in the link 1300. Inlet port 1020 can also be located below the gas outlet port 1050 so that the less dense gas rises above the relatively denser water, so that only gas exits the separator 1000 through the gas outlet port 1050. Furthermore, the gas outlet port 1050 can be located at the top of the main body 1100, and therefore above the intended liquid level within the separator 1000, again to prevent water from exiting through the outlet port. 1050 gas cylinder.The liquid, sand, and debris outlet port 1030 may be positioned as close to the base of the separator 1000 as is reasonably practical so that liquid and contaminants cannot accumulate below the liquid, sand, and debris outlet port 1030. The upper sensor port 1060 may be located above the upper linkage port 1040a and the lower sensor port 1062 may be provided below the lower linkage port 1040f, so that the upper and lower limit sensors 1064, 1066 may serve as fail-safe protection in the event that the liquid level sensor 1400 fails to detect and account for the liquid level being outside the intended range.

[00145] It should be noted that an increased vertical length of a 1300 ligament can provide additional reaction time for the 2000 valve to release the Petition 870260078306, dated 05 / 08 / 2026, page 41 / 178 33 / 53 liquid, sand, and debris from the main body 1010 of the separator 1000. In some embodiments, the length of the link 1300 and the probe length of the liquid level sensor 1400 can be selected so that the liquid level sensor 1400 has a probe length of approximately 2032 mm (80 inches) and a targeted liquid level (e.g., a midpoint length of the link 1300) of approximately 1397 mm (55 inches).

[00146] A 4002 user interface may be communicatively coupled to the 4000 controller to output real-time or near-real-time data from the 4000 controller to a user. The 4002 user interface may take the form of a general-purpose computer, a handheld device, a siren, a light bar placed on top of the separator, or any other component designed to output information to a user. The 4002 user interface may issue alerts when the liquid level is outside a desired range, a malfunction or obstruction of the 2000 valve is detected, a detected sand density in the fluid flow indicates that the well production volume should be adjusted, or regular maintenance is required.

[00147] In some embodiments, as shown in Figure 8, an electronically controlled valve 4055 may be present in a gas line 4022 downstream of the gas outlet 1050 of the separator 1000. The valve 4055 in the gas line 4022 may include any desired valve type such as, for example, a throttle valve. The valve 4055 may be communicatively coupled to the controller 4000, which controls the operation of the valve 4055 to control the gas flow through the separator 1000. The controller 4000 may communicate with one or both the valve 4055 and the valve 2000 to control fluid flow through the separator 1000 to maintain the desired liquid level within the separator 1000.

[00148] In some embodiments, a bypass line 4056 may be fluidly coupled to the gas outlet 1050 to bypass the electronically controlled valve 4055 in the gas line 4022. A bypass valve 4058 is disposed along the bypass line 4056, and the valve 4058 may be selectively opened to allow gas to flow around the electronically controlled valve 4055. The bypass line 4056 and the bypass valve 4058 may be smaller than the gas line 4022 and the electronically controlled valve 4055, respectively, to handle the lower volumetric gas flow rates exiting the separator during the phases. Petition 870260078306, dated 05 / 08 / 2026, p. 42 / 178 34 / 53 initial return operations where very little gas is present. The bypass valve 4058 can be operated manually or electronically. The bypass line 4056 and valve 4058 can be used to remove air from separator 1000 during the initial return operation phases, for example, when extremely large volumes of liquid, sand, and debris are flowing through separator 1000 without much gas. To maintain the liquid level within separator 1000 within a desired range during the initial return phases, the electronically controlled valve 4055 on gas line 4022 can be closed. A gas pocket eventually forms in an upper portion of the inner chamber 1100 of separator 1000, at which point separator 1000 would need to have air removed to remove the gas pocket and restore the liquid level. The 4058 bypass valve can be opened and then closed again, thereby removing the pocket of gas.The process can be repeated at regular intervals through return operations, these intervals becoming progressively shorter until a stable gas flow is established through separator 1000. Once a stable gas flow is established through separator 1000, bypass line 4056 can be closed and the electronically controlled valve 4055 operated after the initial return operations.

[00149] Having generally described the components of separator 1000, a detailed operation of separator 1000 will now be described with reference to Figure 8. The gas initially enters separator 1000 from wellbore W through inlet port 1020. Inlet port 1020 can be fluidly connected to wellbore W by pipe 4100. The gas entering separator 1000 may carry with it various contaminants, including water (both in liquid and vapor form) and hydraulic fracturing sand (i.e., fracturing). In addition, the gas may carry debris, such as fragments (e.g., plug pieces) of plugs used during the fracturing process. Once inside separator 1000, all media, including gas, liquid, sand, and debris, can flow through tube 1022 and be deflected downward by deflector 1024, in the direction of arrow A. In an alternative embodiment, tube 1022 may have multiple openings, as shown in Figure 7A.

[00150] Solid contaminants, such as sand and debris, settle at the bottom of the inner chamber 1010. Liquid, such as water, fills the inner chamber 1010 from bottom to top, establishing a liquid level L. Gas, being less dense Petition 870260078306, dated 05 / 08 / 2026, p. 43 / 178 35 / 53 that the liquid flows towards the top of the inner chamber 1010 in the direction of arrow B, rises above the liquid to fill the top of the inner chamber 1010. A diffuser (e.g., 1054 of Figure 6) inside the separator 1000 can assist the upward movement of the gas through the inner chamber 1010. Once the liquid level L reaches the lowest connecting port 1040f, the gas and liquid can flow freely between the inner chamber 1010 and the connecting port 1300 in the direction of arrows C through the connecting ports 1040a-1040f. The liquid level L thus equalizes between the inner chamber 1010 and the connecting port 1300.

[00151] The gas flows out of separator 1000 through gas outlet port 1050 in the direction of arrow D to pipe 4022. Pipe 4022 may in turn be fluidly connected to downstream components (e.g., a line heater or molecular dryer).

[00152] As the liquid level L rises from the continued influx from the wellbore, valve 2000 can be opened to allow liquid, sand, and debris to flow out of separator 1000 in the direction of arrow E through outlet port 1030. Specifically, liquid, sand, and debris can flow through pipe 4300 to holding tank 3000, as shown in Figure 8. To prevent large debris, such as plug fragments, from clogging or damaging valve 2000, a filter 4110 can be provided upstream of valve 2000 to capture such debris.

[00153] Valve 2000 can be opened and closed by controller 4000 based on the liquid level L as measured by liquid level sensor 1400. Controller 4000 can receive a signal from liquid level sensor 1400 indicating the vertical position of liquid level L. If liquid level L is above a maximum safe liquid level Lmax, controller 4000 can transmit a signal to valve 2000 to open valve 2000. With valve 2000 open, liquid, sand, and debris inside the inner chamber 1010 can flow out of the outlet port 1030 in the direction of arrow E, thereby lowering the liquid level L.

[00154] Valve 2000 can remain open until the liquid level L has reached a minimum safe liquid level Lmin. When liquid level sensor 1400 detects that the liquid level L has reached the minimum safe liquid level Lmin, liquid level sensor 1400 can transmit a signal to controller 4000 which, in turn, can transmit a signal to valve 2000 to close valve 2000. Petition 870260078306, dated 05 / 08 / 2026, page 44 / 178 36 / 53 With valve 2000 closed, the liquid level L can rise again to the maximum safe liquid level Lmax, at which point controller 4000 can again open valve 2000 based on the determination of liquid level sensor 1400. Valve 2000 can be repeatedly opened and closed in this mode to maintain the liquid level L between the maximum safe liquid level Lmax and the minimum safe liquid level Lmin as gas is extracted from the wellbore. In some embodiments, valve 4055 on gas line 4022 can be similarly opened and closed to maintain the liquid level L between the maximum safe liquid level Lmax and the minimum safe liquid level Lmin as gas is extracted from the wellbore. By maintaining the liquid level L in this mode, liquid water is prevented from flowing out of gas outlet port 1050 and gas is prevented from flowing out of outlet port 1030.

[00155] As shown in Figure 8, the maximum safe fluid level Lmax may correspond to the position of the highest ligament gate 1040a, and the minimum safe fluid level Lmin may correspond to the position of the lowest ligament gate 1040d. However, it should be understood that the maximum safe fluid level Lmax and the minimum safe fluid level Lmin need not correspond to the positions of the third top ligament gate 1040c and the lowest ligament gate 1040f, but could instead correspond to any locations where fluid may be present in the ligament 1300.

[00156] With continued reference to Figure 8, the pipe 4100 leading from the wellbore to the separator 1000 may include a shut-off valve 4120, which may be manually or automatically closed to stop the flow to the separator 1000. In some embodiments, the shut-off valve 4120 may be controlled by the controller 4000 in response to measurements made by the liquid level sensor 1400, the upper and lower limit sensors 1062, 1066, the density sensors 4052, 4054, or a combination of all the sensors. The controller 4000 can receive signals from the limit sensors 1064 and 1066, and based on these signals, transmit a signal to activate the shut-off valve 4120. If, based on a signal received from the upper limit sensor 1064, the controller 4000 determines that the liquid level inside the inner chamber 1010 is above a predetermined maximum, the controller 4000 can transmit a signal to close the shut-off valve 4120.Closing the shut-off valve 4120 stops the flow. Petition 870260078306, dated 05 / 08 / 2026, page 45 / 178 37 / 53 inside and outside the separator 1000 is interrupted, thereby preventing the liquid from advancing downstream.

[00157] Similarly, controller 4000 can transmit a signal to close shut-off valve 4120 if controller 4000 determines that the liquid level inside the inner chamber 1010 is below a predetermined minimum, based on a signal received from the lower limit sensor 1066. By closing shut-off valve 4120, the flow into and out of separator 1000 is interrupted, thereby preventing separator 1000 from running dry and the pressure from becoming too high inside the holding tank 3000.

[00158] The controller 4000 can also transmit a signal to open, close, or modulate the shut-off valve 4120 to control the fluid flow into the well separator 1000 based on a determination of the sand concentration of the fluid flowing through the separator 1000. As discussed above, the controller 4000 can determine the real-time sand concentration flowing through the separator 1000 based on measurements made by the density sensors 4052, 4054. The controller 4000 could also be programmed to close the valve 4120 if fluid flow is detected through the valve 2000 by the sensor 4054 when the valve 2000 is in the closed position.

[00159] In some embodiments, the controller 4000 may use proportional integral derivative (PID) logic to continuously and / or repeatedly receive measurement signals from the liquid level sensor 1400, and subsequently actuate the valve 2000 and / or valve 4055 to maintain the desired liquid level L in the mode described herein. Similarly, the controller 4000 may use proportional integral derivative (PID) logic to continuously and / or repeatedly receive measurement signals from the upper and lower limit sensors 1064, 1066 and / or the density sensors 4052, 4054 and subsequently actuate the shut-off valve 4120 in response to the fluid level within the inner chamber 1010 and / or the concentration of sand flowing through the separator 1000.

[00160] As described herein, the 4000 controller can communicate with the 1400 liquid level sensor, the 2000 valve, the 4055 valve, the 1064 and 1066 upper and lower limit sensors, the 4052 and 4054 density sensors, the 4120 shut-off valve, and the 4050 valve position sensor. The 4000 controller can Petition 870260078306, dated 05 / 08 / 2026, page 46 / 178 38 / 53 include at least one processor programmed or configured to execute instructions stored in computer-readable media. The controller 400 can communicate with the liquid level sensor 1400, the valve 2000, the valve 4055, the upper and lower limit sensors 1064, 1066, the density sensors 4052, 4054, the shut-off valve 4120 and the valve position sensor 4050 by any wired or wireless communication protocols and interfaces such as 420 milliampere HART signal, Ethernet, fiber optic, coaxial, infrared, radio frequency (RF), Universal Serial Bus (USB), Wi-Fi®, cellular network, and / or similar. The controller 4000 can be in communication with a user interface 4002 to provide real-time feedback to the electronic controller and / or to an operator on the liquid level L inside the internal chamber 1010, and / or real-time feedback that the separator 1000 and its associated components are operating properly.

[00161] Referring now to Figures 13 and 14, separator 1000 can be used as a component of a gas processing plant 5000 which includes separator 1000 and a line heater and choke assembly 5100. Figure 13 shows two separators 1000 feeding a single line heater and choke assembly 5100, although a single separator 1000 can also be used. The two separators 1000 can be used to produce gas from two different wells simultaneously. As illustrated, the two separators 1000 can be positioned side by side and connected to the same downstream equipment slip 1090 (e.g., a single line heater and choke assembly 5100 for both separators 1000), thereby saving space. The 5100 line heater and choke assembly includes a 5200 line heater and a 5300 choke.Gas, water, and contaminants flow into the W-well separator 1000, where the water and contaminants are separated from the gas as described herein. The gas flowing out of the separator 1000 through the gas outlet port 1050 and piping 4022 flows into the line heater 5200. The line heater 5200 may include, for example, one or more coils arranged in a heated glycol bath. The gas from the separator 1000 flows through the coils until the gas reaches a desired temperature and / or pressure. The gas exiting the line heater 5200 then flows through the throttle 5300, which reduces the gas pressure to a desired line pressure, for example 9,600 kPa (1,400 psi). Petition 870260078306, dated 05 / 08 / 2026, p. 47 / 178 39 / 53

[00162] Referring now to Figure 15, a flowchart of a process 6000 for gas production from a well is shown as substantially described herein. Process 6000 may be a process for producing a pressurized natural gas stream from a fluid being produced from a wellbore. Process 6000 may be fully or partially automated by controller 4000. In step 602, the gas flow to separator 1000 from wellbore W may be initiated. This may be achieved, for example, by opening shut-off valve 4120 via controller 4000. Alternatively, shut-off valve 4120 may be manually opened. The fluid may be directed into separator 1000 at a pressure substantially equal to the pressure of the fluid being produced from the wellbore.

[00163] In step 604, the liquid level L inside the inner chamber 1010 can be determined. Specifically, the liquid level sensor 1400 can transmit a signal indicating the liquid level L to the controller 4000. The liquid level sensor 1400 can provide real-time feedback of the liquid level L to the controller 4000.

[00164] Process 6000 may also include controlling the liquid level L within separator 1000 between two predetermined set points (e.g., Lmax and Lmin) by regulating the flow of liquid, sand, and other solid debris out of a lower portion of separator 1000. For example, in step 606, the electronically controlled valve 2000 may be opened or closed, or modulated, in response to the determination of the liquid level L. Specifically, controller 4000 may transmit a signal to open valve 2000 if the liquid level L is above the maximum safe liquid level Lmax, and controller 4000 may transmit a signal to close valve 2000 if the liquid level L is below the minimum safe liquid level Lmin. Modulation of valve 2000 also allows accumulated sand and debris to exit separator 1000, so that manual cleaning is not required.Process 6000 may also include directing the gas (substantially clean of liquid, sand, and debris) out of separator 1000 at a pressure substantially equal to the wellbore pressure.

[00165] In step 608, the liquid level L inside the inner chamber 1010 of the separator 1000 can be checked or confirmed to be within an appropriate range using the upper limit sensor 1064 and / or the lower limit sensor 1066 in case of a malfunction of the liquid level sensor 1400. Specifically, Petition 870260078306, dated 05 / 08 / 2026, page 48 / 178 40 / 53 the upper limit sensor 1064 and / or the lower limit sensor 1066 can transmit a signal to the controller 4000 indicating the presence of liquid at the upper sensor port 1060 and at the lower sensor port 1062.

[00166] In step 610, the shut-off valve 4120 can be closed in response to the determination that the liquid level L within the inner chamber 1010 is outside the appropriate range. Specifically, the controller 4000 can transmit a signal to close the shut-off valve 4120 if the liquid level L is above the upper limit sensor 1064 or if the liquid level L is below the lower limit sensor 1066. Steps 604, 606, 608, and 610 can be repeated periodically, continuously, and / or at predetermined time intervals during the well's lifespan.

[00167] In some embodiments, the controller 4000 may require a communication establishment check between the liquid level sensor 1400 and the upper and lower limit sensors 1064, 1066 to actuate the valve 2000. That is, the controller 4000 may require that the liquid level determined by the liquid level sensor 1400 matches the liquid level determined by the upper and / or lower limit sensors 1064, 1066 before actuating the valve 2000. The controller 4000 may use this communication establishment to diagnose a fault in the liquid level sensor 1400, the upper limit sensor 1064, and / or the lower limit sensor 1066. The controller 4000 may use this fault detection mode to ensure that the separator 1000 is operating properly and may provide feedback to an operator that the separator 1000 is (or is not) operating. appropriately.With this precision control, real-time electronic feedback provided by the operator to ensure that separator 1000 is operating properly, and redundant protections to ensure that separator 1000 does not overflow or empty, it is virtually impossible for gas to be lost to on-site tanks.

[00168] The system and process of the present description may allow higher gas and liquid flow rates than the existing sand separator and pre-existing GPU configuration. Because fluid separation is occurring downstream of the pressure cutoff in the GPU within the pre-existing configuration, and gas expansion and associated system velocities increase, turbulence within the GPU is amplified. As such, the pre-existing system may be limited to a maximum of 60 Petition 870260078306, dated 05 / 08 / 2026, page 49 / 178 41 / 53 barrels / hour. The separator 1000 of the present description allows liquid separation to occur at significantly higher pressures than in the existing system, meaning that the liquid separation of the present description occurs at a lower fluid velocity and consequently less turbulent flow. For example, the separator 1000 can allow liquid handling capacities beyond 200 barrels / hour using a separator 1000 with a working volume of only 8 barrels. This advantage can eliminate the need to employ third-party return services, which require process flow rates on the order of 120 barrels / hour. Furthermore, labor is greatly reduced using the described technology since almost all aspects of the operation are automated. The operation can be considered eFlowback.

[00169] Due to safety concerns associated with gas production, any of the components of separator 1000 described herein may be provided in duplicate and / or may include redundant systems to ensure the safe operation of separator 1000. Furthermore, two separators 1000, 1001 may be constructed on a skid and used in series, the first acting as a primary separator and the second as a polishing or reserve reservoir in case fluid is loaded from the primary reservoir. This arrangement is illustrated in Figure 21. This configuration is particularly advantageous in systems using a molecular dryer, as it is critical that the free liquid never comes into contact with the molecular dryer and the molecular filter, desiccant, or other material it contains.Alternatively, in operations where some free liquid transport is not problematic, the 1000 separator can be used in parallel, for example, as shown in Figure 17, where the 1000 separator is operating in tandem with the conventional production equipment shown in Figure 1. In this example, the skid can have two 1000 separators in parallel that can be used to return two wells, as shown in Figure 17A. Finally, in this configuration, the system can serve in two unique applications.

[00170] Having generally described the separator 1000 and its operation, several applications in which the separator 1000 can be used will now be described with reference to Figures 17-21. However, as those skilled in the art will appreciate, the separator 1000 can also be used in conjunction with a conventional GPU 20 (as shown in Figure 1). Figure 17 illustrates an installation of Petition 870260078306, dated 05 / 08 / 2026, page 50 / 178 42 / 53 gas production 700 which includes separator 1000 being used to perform a return operation to a well. The well is designated in Figure 17 by a tree 702, which is located at the wellhead. Tree 702 may be a standard Christmas tree 702 located above a well and comprising multiple valves and boreholes through which fluid can be directed from the well. Tree 702 is configured to emit the fluid produced from a wellbore. The fluid produced from the wellbore may include gas, liquid, sand, and debris.

[00171] During return operations, liquid, sand, and debris can constitute a significant proportion of the fluid being produced from the wellbore. Return operations can last 5 days, 1 week, 2 weeks, or even a month or more. The permanent production equipment used to process the well gas output was not designed to handle the large quantities of liquid, sand, and debris that are removed from the well during return operations. The separator 1000 described in detail above can be used to clean the liquid, sand, and debris from the well fluid during return operations, so that the same gas processing equipment (e.g., gas processing unit 704) can be used to process the gas during return operations and during the longer production phase after return operations.The gas processing unit 704 may include at least one throttle to reduce the pressure of the gas or fluid flowing through it. The illustrated arrangement of separator 1000 and gas processing unit 704 used to provide return operations has a much smaller footprint than conventional third-party return dispersers.

[00172] The separator 1000 can be connected to the tree 702 and the gas production unit 704 by means of a series of flow paths, each flow path taking the form of rigid or flexible piping. The gas production installation 700 may include, for example, a first flow path 706 connecting a first outlet 708 of the tree 702 to the inlet 1020 of the separator 1000. The inlet 1020 supplies the fluid into the separator 1000 at a first pressure. The fluid may comprise liquid, gas, sand, and debris. As illustrated and described in detail above, the separator 1000 includes the inlet 1020 and a gas outlet 1050 through which the gas (separated from the liquid, sand, and debris) is supplied from the separator 1000. The gas production installation 700 may also include a second Petition 870260078306, dated 05 / 08 / 2026, page 51 / 178 43 / 53 flow path 710 connecting a second outlet 712 of the gas production unit 704. Fluid can flow from the well directly to the gas production unit 704 through the second flow path 710 when a valve on the second outlet 712 is open. The gas production installation 700 may further include a third flow path 714 connecting the gas outlet 1050 of the separator to the gas production unit 704 or, more specifically, the second flow path 710 leading to the gas production unit 704. As illustrated, a valve 716 may be disposed along the third flow path 714 to selectively open and close the third flow path 714.As illustrated in Figures 17 and 17A, a bypass valve system (e.g., including an electronically controlled valve 4055, bypass line 4056, bypass valve 4058, and / or gas metering device 1057 as discussed with reference to Figure 8) may be arranged along the third flow path 714 in addition to valve 716. The bypass valve system may allow control of the gas flowing from separator 1000 through all return operations (e.g., when it may be desirable to remove air from the separator 1000 reservoir) and after return operations when a substantial gas flow has been established. In some embodiments, valve 716 may not be present so that the bypass valve system provides all flow control through the third flow path 714.

[00173] During return operations, a valve on the second outlet 712 of the shaft 702 can be closed while a valve on the first outlet 708 of the shaft 702 can be opened. In this way, the fluid containing large quantities of liquid, sand, and debris is directed to the separator 1000 through the first flow path 706. The separator 1000 can remove the liquid, sand, and debris through the outlet 1030 by controlling the valve 2000 according to the method described above. The gas separated from the liquid, sand, and debris is supplied out of the separator 1000 through the outlet 1050 and through the third flow path 714 and the second flow path 710 to the gas production unit 704 (e.g., following the arrows 718). The liquid, sand, and debris separated from the gas can pass through a scrap collector or other type of filter 4110 so as not to clog valve 2000.Downstream of valve 2000, liquid, sand, and debris can be collected at an outlet of gas production unit 704 through which the liquid, sand, and / or debris can also be directed out of gas production unit 704. Petition 870260078306, dated 05 / 08 / 2026, page 52 / 178 44 / 53

[00174] After the return operations are completed or once a suitable gas volume for the permanent equipment is reached (for example, once the well is producing large amounts of gas), the valve on the second outlet 712 of the tree 702 can be opened and the valve on the first outlet 708 closed, thereby allowing fluid to flow from the well directly to the gas production unit 704 instead of the separator 1000. Thus, the separator 1000 can alone or in combination with a conventional system as shown in Figure 1 replace a conventional return disperser to remove large quantities of liquid, sand, and debris.

[00175] Referring to Figures 18-21, the separator 1000 according to the present description can be used not only for gas production for a pipeline, but also to generate other products or energy using substantially less on-site equipment and at a lower cost than conventional methods. This is because the described separator 1000 is capable of producing a highly pressurized and substantially clean gas stream. Removing all free liquid from the gas stream at approximately wellhead pressure (before any pressure cut) allows for new and improved uses of wellhead energy. For example, wellhead energy can be used for one or more power generation purposes, such as subsequent production of hydrogen, oxygen, naturally formed compressed natural gas (CNG), and liquefied natural gas (LNG), and other useful products.

[00176] Figure 18 illustrates a system 800 that can utilize the pressurized gas flow to simultaneously feed one or more processes in addition to, or instead of, supplying gas to a pipeline 810. Each of the components illustrated in Figure 18 can be an individual piece of mobile equipment brought to a well site. The separator 1000, as illustrated, can generally include the inlet 1020, the liquid, sand, and debris outlet 1030, and the gas outlet 1050. The separator 1000 can include the same components and operate as described above with reference to any of Figures 2-12 and 16. The inlet 1020 can supply fluid being produced from a wellbore into the separator 1000 at an initial pressure, and the fluid can comprise liquid, gas, sand, and debris. Gas outlet 1050 is configured to supply gas separated from liquid, sand, and debris out of separator 1000 at a second pressure. The second pressure can be Petition 870260078306, dated 05 / 08 / 2026, p. 53 / 178 45 / 53 substantially equivalent to the first pressure in some embodiments. In other embodiments, the second pressure may be different from the first pressure. Outlet 1050 may be connected to a particulate filter 802, which may be connected to a molecular dryer 804. As such, outlet 1050 is connected to the molecular dryer 804. Outlet 1050 may also or alternatively be connected to a gas processing unit 704.

[00177] The 804 molecular dryer is a molecular vapor dryer, which removes water vapor from the gas stream. As those skilled in the art will appreciate, the 804 molecular dryer can be a molecular filter, a membrane, or any other device or process capable of removing all or most of the water vapor from the gas stream emitted from the 1050 outlet, so that the remaining gas stream can meet the parts per million (PPM) requirements needed to feed certain downstream equipment. As illustrated, the 804 molecular dryer has at least one outlet through which the substantially removed water vapor gas is directed out of the 804 molecular dryer. As those skilled in the art will appreciate, the molecular dryer could be any device that removes water vapor from gas.

[00178] After passing through the molecular dryer 804, the gas stream can be split and / or directed downstream to perform one or more processes. In the illustrated embodiment, the gas stream is split after the molecular dryer 804. The different portions of the gas stream are then fed to a CNG filling station 806, fed into a pipeline 810, liquefied to produce LNG 818, used to generate electricity 812, and the energy would then be used to generate hydrogen 814. As those skilled in the art will appreciate, the CNG filling station 806 can be stationary storage tanks or trucks. The gas stream directed to the CNG filling station is compressed natural gas, which the industry defines as CNG. As the CNG produced through this process does not use external or human-made compression, it will be referred to herein as naturally compressed natural gas.Although all these processes are illustrated in Figure 18, it should be understood that more or fewer processes can be performed using the pressurized gas flow emitted from molecular dryer 804. One or more gas flows can be emitted from molecular dryer 804 at a third pressure, which can be substantially higher. Petition 870260078306, dated 05 / 08 / 2026, p. 54 / 178 46 / 53 the same as or different from one or both of the first and second pressures described above.

[00179] As illustrated, the CNG filling station 806 can be connected to an outlet of the molecular dryer 804 so that a first gas stream emitted from the molecular dryer can be directed to the CNG filling station 806. In some embodiments, a pressure control valve 820 is disposed between the CNG filling station and the molecular dryer to reduce or otherwise control the pressure of the gas being directed out of the molecular dryer from the third pressure to a lower pressure. For example, the third pressure may be approximately 34,500 kPa (5,000 psi), while the fourth pressure may be approximately 24,840 kPa (3,600 psi). In this way, the gas flow is reduced to a desired pressure required to fill CNG tanks. In other embodiments, the pressure control valve 820 may not be present.

[00180] Modern CNG is typically compressed from pipeline pressures as low as 345 kPa (50 psi) up to pressures of approximately 34,500 kPa (5,000 psi). By precisely removing all free liquid from the well at borehole pressures via separator 1000 and molecular dryer 804, CNG can be generated without compression. There is a significant reduction in capital, operating costs, and emissions associated with eliminating the compression element from CNG production and allowing borehole pressure to provide the pressure needed to fill high-pressure tanks or pipelines.

[00181] As illustrated in Figure 18, system 800 may comprise a turboexpander 808 connected to an outlet of the molecular dryer 804. An exemplary turboexpander converts changes in pressure into rotational / mechanical energy that can be used for compression, power generation, and the like. (As used herein, a turboexpander is defined as a device that creates mechanical energy from a pressure differential.) It may also produce cooling through the Jules Thompson Effect. It may include and be coupled with or connected to a gas compressor, an electric generator, or any other device, system, or process that requires the mechanical and / or rotational energy that it produces. As those skilled in the art will appreciate, whenever a turboexpander, a piston expander, a reciprocating expander, a centrifugal compressor, or a [unclear] is described, Petition 870260078306, dated 05 / 08 / 2026, page 55 / 178 A positive displacement expander (47 / 53) can be used in its place. An exemplary turboexpander compressor combination could include a turboexpander / compressor of the Compander™ brand. The turboexpander 808 can be fed by the gas directed out of the molecular dryer and used to generate electricity (812) and subsequently hydrogen (814) through electrolysis. The turboexpander 808 may include an inlet to receive the pressurized clean gas flow from the molecular dryer 804 and one or more outlets through which the gas emitted from the turboexpander is at a lower pressure. In some embodiments, the system 800 may include a pressure control valve 822 disposed between the outlet of the molecular dryer 804 and the turboexpander 808 to reduce the pressure of the gas being directed out of the molecular dryer from one pressure to a lower pressure. For example, the pressure control valve 822 may reduce the pressure from approximately 34,500 kPa (5.000 psi) to approximately 17,250 kPa (2,500 psi) or the technical limits of existing turboexpander technology. Existing Utica wells can generate the equivalent of over 10,000 horsepower. This can reduce the gas flow to a desired pressure so that gas flow is emitted from the turboexpander at an appropriate piping pressure (e.g., 6,900 kPa (1,000 psi)). It should be noted that the pressures listed here are merely examples and other embodiments may include gas flow at different pressures.

[00182] The turboexpander 808 can function as a generator, converting the pressure drop of the gas moving through the turboexpander 808 into electricity (812). The pressurized gas flow is able to be used in a turboexpander due to the fact that all the liquid has been removed from the gas flow (e.g., through the separator 1000 and the molecular dryer 804) without a significant pressure drop. In some embodiments, the electricity generated (812) can be used to power equipment on-site or distributed to the local power grid. In some embodiments, the electricity can be used to generate emission-free hydrogen through electrolysis (814). Using the separator 1000, the molecular dryer 804, and the turboexpander 808, the system 800 can be able to generate electricity at the well with zero emissions.

[00183] As illustrated, system 800 may include a gas pipe 810 connected to the outlet of the turboexpander 808. In other embodiments, system 800 may include a gas pipe 810 connected to an outlet of the molecular dryer. Petition 870260078306, dated 05 / 08 / 2026, page 56 / 178 48 / 53 804. Gas pipeline 810 can supply natural gas to a natural gas pipeline. As will be understood by one skilled in the art, gas pipeline 810 can supply natural gas at a pipeline pressure (e.g., 6,900 kPa (1,000 psi)) that is lower than the pressure at which the gas is emitted from the molecular dryer 804 (e.g., 34,500 kPa (5,000 psi)). As such, the gas pressure is reduced before supplying the gas to pipeline 810. This pipeline pressure can be a pressure at which the natural gas network supplies gas to communities. In Figure 18, for example, turboexpander 808 is connected between gas pipeline 810 and molecular dryer 804 to reduce the pressure of the gas being directed through turboexpander 808 to a lower pressure that is substantially equal to the desired pipeline pressure and generate electricity and subsequently hydrogen in the process.The pressure control valve 822 can also reduce the pressure exiting the molecular dryer. In some embodiments, although not explicitly stated, the turboexpander may be omitted, replaced by a JT (Joule Thomson) valve, or the piping 810 may not be connected to the turboexpander 808. In such cases, a pressure control valve 822 may be connected between the gas piping 810 and the molecular dryer 804, and the pressure control valve 822 may reduce the pressure of the gas being directed out of the molecular dryer 804 to a pressure that is substantially equal to the desired piping pressure.

[00184] The described system 800 can supply gas to pipeline 810 with reduced or no emissions. Due to the use of the described separator 1000 in combination with the molecular dryer 804, the gas supplied to pipeline 810 and / or other downstream components of system 800 is substantially free of water vapor and contaminants. When the gas pressure is reduced, by a pressure control valve 822, JT valve, turboexpander 808, or all three, there is no possibility of water vapor in the gas stream freezing and damaging equipment. Therefore, no burner or other heat sources are needed to prevent water from freezing in the gas stream. As such, the pressure reduction required to bring the gas stream to pipeline pressure can be performed without the emissions released by conventional burners.

[00185] The separator 1000, molecular dryer 804 and turboexpander 808 can also enable the generation of LNG 818 without electricity or external power. The LNG Petition 870260078306, dated 05 / 08 / 2026, page 57 / 178 49 / 53 818 is natural gas that has been cryogenically cooled to -162.2°C (-260°F) to liquefy LNG 818 and is typically stored at 34.5 kPa (5 PSIG) or less. As illustrated, system 800 may include a cold box 816 connected to the turboexpander 808. In other embodiments, though not explicitly stated, system 800 may include a cold box 816 connected to an outlet of the molecular dryer 804. (The cold box 816 is configured to capture the cold gas exiting the turboexpander 808 (or molecular dryer 804) in order to produce LNG 818 at a lower pressure than the incoming gas. As used herein, cold box is defined as one or more components of a heat exchanger, valves, controllers, heat retention and all other devices and processes associated to support the liquefaction process). In the embodiment of Figure 18, the turboexpander 808 can produce supercooled gas in addition to electricity 812 and subsequently hydrogen 814.The turboexpander 808 can be connected to the refrigeration compressor. The cold box 816 can be connected to the refrigerated fluid or gas outlet to receive the cooling fluid 824 to cryogenically cool the gas exiting the turboexpander 808 (or molecular dryer 804).

[00186] The described system 800, in which pressurized gas is supplied via separator 1000 and molecular dryer 804, can help reduce the capital and operating expenses for a liquefaction plant to generate LNG, since no electricity or external power is required to reduce gas pressure or operate the cold box 816. The described system 800 can also reduce the environmental and emissions footprint required for LNG production. Depending on the gas composition, additional gas conditioning downstream of the molecular dryer may be required for LNG production, such as removal of carbon dioxide and heavy hydrocarbons (e.g., butane, pentane, etc.). Consequently, the embodiments shown in Figures 18-21 optionally include a conditioner 805 immediately downstream of the molecular dryer 804.

[00187] Figure 19 shows another system 900 that can use the pressurized gas flow to simultaneously feed one or more processes in addition to, or instead of, supplying gas to a pipeline 810. The system 900 shown in Figure 19 is similar to the system 800 shown in Figure 18, except that the pressure control valves 820 and 822 have been replaced by another turboexpander 826. This second turboexpander 826 is located between the outlet of the molecular dryer 804 and the Petition 870260078306, dated 05 / 08 / 2026, page 58 / 178 50 / 53 turboexpander 808. Turboexpander 826 can reduce the pressure of the gas being directed out of the molecular dryer 804, and turboexpander 808 can then reduce the pressure of the gas being directed out of turboexpander 826. In general, any pressure drop that is necessary to supply gas to a downstream process can be achieved using a turboexpander 808, 826 as illustrated. This can further help conserve energy by converting any pressure drops into work to generate electricity 812, 828, hydrogen through hydrolysis 814, 830, and / or cooling fluid 824, 832 to supply a cold box 816. Any desired number of turboexpanders can be connected in series between the molecular dryer 804 and the downstream component(s) that need a reduced-pressure gas flow.

[00188] As shown in Figure 19, system 900 may include a compressed natural gas filling station 806 connected to an outlet of the nearest turboexpander 826 to the molecular dryer 804. The turboexpander 826 connected between the compressed natural gas filling station 806 and the molecular dryer 804 may reduce the pressure of the gas being directed out of the molecular dryer to a lower pressure that can be used to fill CNG tanks (806). The CNG filling station 806 may need gas supplied at a higher pressure than some other downstream processes (e.g., LNG generation or pipeline supply), which is why it receives gas output after the first pressure drop through the turboexpander 826.

[00189] Figure 20 shows yet another system 2001 that can utilize the pressurized gas flow to simultaneously feed one or more processes in addition to, or instead of, supplying gas to a pipeline 810. The system 2001 shown in Figure 20 is similar to the system 800 shown in Figure 19, except that an auxiliary cooler 852 is connected to the cold box 816 to additionally cool the hydrogen 848 and / or oxygen 850 being produced through the electrolysis process 846 to produce liquid hydrogen (H2) and liquid oxygen (O2). As those skilled in the art will appreciate, since oxygen liquefies at a higher temperature than hydrogen, each would require its own unique flow path from the auxiliary cooler 852 or alternatively separate auxiliary heat exchange / cooling devices. The energy 842 emitted from turboexpanders 808 and 826 through the power generation and cooling stages 840 is used to separate hydrogen 848 from Petition 870260078306, dated 05 / 08 / 2026, p. 59 / 178 51 / 53 Oxygen 850 in an electrolysis process 846. Hydrogen 848 and oxygen 850 are then fed into the cold box 816 (which is cooled as noted above with reference to Figures 18 and 19 by means of the cooling fluid exiting the turboexpanders 808 and 826 as the gas passes through these devices). The cold box 816 can produce LNG 818 as described in Figures 18 and 19 and also liquid oxygen 854 and liquid hydrogen 856 with the aid of the auxiliary cooler 852, which could be fed by a turboexpander electrically or mechanically by compression. The auxiliary cooler 852 further cools these gases to the point where they undergo a phase change and become liquids. Liquid oxygen 854 is cooled to approximately -182.77°C (-297°F) and liquid hydrogen 856 is cooled to approximately -252.77°C (-423°F). Oxygen 850 is stored at approximately 2.415 kPa (350 psi) or lower as it passes through auxiliary cooler 852 and hydrogen 848 is stored at approximately 310.5 kPa (45 psi) as it passes through auxiliary cooler 852.

[00190] Figure 20 illustrates that another turboexpander 834 may be connected downstream of turboexpander 808 to generate additional energy and cooling by harnessing the generated energy to further reduce the gas pressure to a pressure that would allow it to be transported through gas piping 810. In the embodiments shown in and described in reference to Figures 18-21, a compressor may optionally be connected to, and powered by, or turboexpanders within the system, either by direct connection compression or by electricity generated within the process. These compressors may be used to facilitate the compression of hydrogen, oxygen, natural gas, refrigerant gases or other gases in a truck, a separate pipeline, the cold box or for mixing with natural gas in pipeline 810.

[00191] The embodiment in Figure 20 further proposes to take advantage of the additional energy of the high-pressure liquid exiting the bottom of separator 1000. First, the liquid, sand, and debris exiting separator 1000 through outlet port 1030 must have the solid material removed from it. This is done by passing the fluid mixture through a solids removal mechanism 860. As those skilled in the art will recognize, the mechanism for removing solids from the liquid may include a filter or scrap collector or similar device. Once the sand and other debris are removed Petition 870260078306, dated 05 / 08 / 2026, page 60 / 178 52 / 53 solids are removed, the resulting high-pressure liquid can be passed through a hydroelectric turbine 870, which in turn can generate electricity 812 for local energy consumption (e.g., powering the various equipment used in the processes mentioned above) and / or for supply to a power grid. As will be appreciated by those skilled in the art, multiple hydroelectric turbines 870 can be connected in series to harness as much energy as possible from the high-pressure liquid.

[00192] The embodiment of Figure 20 may further comprise a compressor 880 fluidly connected to the electrolysis device 846 into which hydrogen 848 may be fed to enable the hydrogen to be compressed and subsequently supplied to customers, for example, via a truck 882 or gas pipeline 810. Alternatively, hydrogen 848 may be supplied via a dedicated hydrogen pipeline 890. As those skilled in the art will appreciate, the compressed hydrogen may be mixed with natural gas as burned for power generation since newer gas turbine engines are capable of burning a mixture of hydrogen and natural gas. In an exemplary embodiment, the fuel for such a turbine contains 15% hydrogen. Similarly, the truck 882 may transport the hydrogen gas for subsequent mixing or other use at a remote location.

[00193] Figure 21 illustrates system 2001 of Figure 20 having two separators 1000 and 1001 coupled in series to provide the flow of pressurized gas to the molecular dryer 804 and other downstream components, as referenced above.

[00194] Systems 800, 900, and 2001 of Figures 18-21 are merely examples of different process arrangements that can be combined to utilize the pressurized gas emitted from separator 1000. Other arrangements may be possible in other embodiments. As free and abundant energy is available through the pressurized gas flow from separator 1000, there is no need to design the entire system around a single product (e.g., CNG, LNG, electricity, or hydrogen). Since CNG and LNG can be produced without compression, all the wasted energy from pressure drops through the system can be harnessed to generate electricity and / or make hydrogen. Petition 870260078306, dated 05 / 08 / 2026, page 61 / 178 53 / 53

[00195] Although various embodiments of a separator, gas processing plant, method, and system have been provided in the above description, those skilled in the art may make modifications and alterations to these aspects without departing from the scope and spirit of the invention. For example, it should be understood that this description contemplates that, as far as possible, one or more features of any aspect may be combined with one or more features of any other aspect. As another specific non-limiting example, since natural gas is often odorless, as those skilled in the art will appreciate, it is customary to add an odorant, such as ethyl mercaptan, so that a gas leak can be detected wherever the gas is being processed or consumed. Therefore, such an odorant can be added to any of the gas products produced according to the present invention.Consequently, the above description is intended to be illustrative rather than restrictive. The invention described herein is defined by the appended claims, and all changes to the invention that fall within the meaning and scope of equivalence of the claims shall be included within its scope. Petition 870260078306, dated 05 / 08 / 2026, p. 62 / 178

Claims

1 / 4 CLAIMS 1. Gas production installation, characterized in that it comprises: a separator for separating one or more of a gas, liquid and solids from a fluid produced in a wellbore, the separator comprising: a vessel defining an internal chamber; a fluid inlet for receiving the fluid into the vessel at a first uncompressed pressure of at least 1,500 psig; and a gas outlet for discharging the gas from the vessel at a pressure substantially equal to the first pressure; a line heater for heating the gas as it exits the separator; and a throttle for reducing the gas pressure as it exits the line heater from the first pressure to a second pressure lower than the first pressure.

2. Gas production installation according to claim 1, characterized in that the separator further comprises: one or more sensors for detecting a liquid level within the inner chamber of the vessel; an electronically controlled valve in fluid communication with a liquid outlet of the separator; and a controller connected to the one or more sensors and the electronically controlled valve, wherein the controller is programmed to actuate the electronically controlled valve so as to regulate a combined flow of liquid and solids through the liquid outlet, based at least in part on the liquid level detected by the one or more sensors.

3. Gas production installation according to claim 2, characterized in that the controller is programmed to actuate the electronically controlled valve in order to maintain a predetermined level of liquid within the inner chamber of the vessel. Petition 870260078306, dated 05 / 08 / 2026, page 63 / 178 2 / 4 4. Gas production installation according to claim 3, characterized in that the separator further comprises a fluid connection communicating with the inner chamber of the vessel, and in which one or more sensors are arranged within the connection.

5. Gas production installation according to claim 1, characterized in that the first pressure is an unregulated pressure of the fluid flowing from the wellbore.

6. Gas production installation according to claim 1, characterized in that it comprises an additional separator fluidically coupled in series or in parallel to the separator on a skid.

7. Gas production installation according to claim 6, characterized in that the separator and the additional separator are fluidically coupled to separate wellbore holes, and in that the separator and the additional separator are fluidically coupled to the line heater and the choke.

8. Gas production installation according to claim 2, characterized in that it further comprises a sand reservoir located downstream of the electronically controlled valve for separating sand from the combined flow of liquid and solids.

9. Gas production installation according to claim 2, characterized in that it further comprises an injector drum type separator located downstream of the electronically controlled valve for separating oil and water from the liquid discharged from the separator.

10. Method for producing a pressurized natural gas flow from a fluid being produced from a wellbore, the fluid comprising liquid, gas and solids, characterized in that it comprises: directing the fluid into a separator at a first pressure; directing the gas out of the separator at a pressure substantially equal to the first pressure; and controlling a liquid level within the separator between two predetermined set points by regulating a flow of liquid and solids out of a lower portion of the separator and / or regulating a gas flow rate out of the separator; wherein the first pressure is substantially equal to the pressure of the fluid being produced from the wellbore, is uncompressed and is at least 1,500 psig.

11. Method according to claim 10, characterized in that it further comprises regulating the flow of fluid being produced from the wellbore into the separator.

12. Method according to claim 10, characterized in that it further comprises conveying the gas from the separator to a line heater and a throttle.

13. Method according to claim 10, characterized in that it further comprises: determining whether the liquid level is above or below a predetermined set point in the separator; initiating the flow of liquid, sand and debris out of the lower portion of the separator if the liquid level is above the predetermined set point; and ceasing the combined flow of liquid, sand and debris out of the lower portion of the separator if the set point is below the predetermined set point.

14. Method according to claim 10, characterized in that it further comprises maintaining (a) a predetermined level of liquid within the separator by opening, closing, and / or modulating an electronically controlled valve connected to a controller in fluid communication with the separator to regulate the combined flow of liquid, sand, and debris from the lower portion of the separator, or (b) a predetermined fixed flow rate of liquid, sand, and debris passing through the electronically controlled valve.

15. A method according to claim 14, characterized in that it further comprises providing, through the controller, at least substantially real-time feedback to an operator of the liquid level within the separator; or further comprising: Petition 870260078306, dated 05 / 08 / 2026, page 65 / 178 4 / 4 determining the liquid level within the separator using a liquid level sensor electronically connected to the controller; and opening, closing, and / or modulating the electronically controlled valve using the electronic controller to regulate the combined flow of liquid, sand, and debris from the lower portion of the separator and thereby maintaining the predetermined liquid level; or further comprises closing the electronically controlled valve where the pressure or density of the combined flow of liquid, sand, and debris from the lower portion of the separator reaches a certain predetermined value or if the electronically controlled valve has experienced erosion.Petition 870260078306, dated 05 / 08 / 2026, p. 66 / 178.

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