CA3173974A1

CA3173974A1 - System and method for oil production equipment that minimizes total emissions

Info

Publication number: CA3173974A1
Application number: CA3173974A
Authority: CA
Inventors: Eyal Aronoff; Gevorg Noland Sargsyan; Joseph E. Palaia; Stevin Nicasio Garcia
Original assignee: Pioneer Energy Inc
Current assignee: Pioneer Energy Inc
Priority date: 2021-02-08
Filing date: 2022-02-08
Publication date: 2022-08-11
Also published as: WO2022170252A1

Abstract

The invention relates to a system for processing wellhead fluids into separate wastewater, stabilized oil, residue gas and an optional propane rich NGL stream, using an architecture which integrates separation and crude stabilization processes at pressure. The system is used as a method to minimize total emissions from oil production and processing facilities.

Description

2 SYSTEM AND METHOD FOR OIL PRODUCTION EQUIPMENT
THAT MINIMIZES TOTAL EMISSIONS
COPYRIGHT STATEMENT
[0001] A portion of the disclosure of this patent document contains material that is subject to copyright protection. The copyright owner has no objection to the facsimile reproduction by anyone of the patent document or the patent disclosure as it appears in the Patent and Trademark Office patent file or records, but otherwise reserves all copyright rights whatsoever.
[0002] Trademarks used in the disclosure of the invention, and the applicants, make no claim to any trademarks referenced.
CROSS-REFERENCE TO RELATED APPLICATIONS

[0003] This application claims the benefit of United States Provisional Patent Applications No. 63147188, filed on February 08, 2021, and United States Provisional Patent Application No. 63148303, filed on February 11, 2021, U.S. Patent application 17/073,286 filed on October 16, 2020, all of which are incorporated by reference herein in their entirety.
BACKGROUND OF THE INVENTION
1) Field of the Invention

[0004] The invention relates to the field of oil and gas production and transportation and methods to reduce the emissions of methane, other hydrocarbons, criteria pollutants, and non-criteria pollutants.

[0005] Natural gas is displacing coal in the power generation sector due to reduced costs and reduced Green House Gas (GHG) emissions. However, current methods of oil and gas CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) production and transportation result in significant emissions of methane, other hydrocarbons, criteria pollutants, and non-criteria pollutants. Methane is a highly potent greenhouse gas, with more than 80 times the climate warming impact of carbon dioxide over the first 20 years after it is released. Other pollutants released from oil and gas production and transportation also result in climate warming impacts, affect regional air quality, produce surface level ozone and smog, negatively affect human health, and result in other environmental and socioeconomical impacts.

[0006] One way to quantify the magnitude of the methane leakage is to divide the total amount of methane produced each year from natural gas and oil infrastructure by the total amount of methane emitted each year by all sources

[0007] The Environmental Protection Agency (EPA) has estimated this methane leak rate to be 1.4 percent.

[0008] However, a recent study that reviewed results from more than 130 other emissions studies shows the U.S. oil and gas industry is leaking 13 million metric tons of methane each year. This means that the methane leak rate is 2.3 percent, indicating that the former EPA study significantly underestimated emissions.

[0009] An Environmental Defense Fund (EDF) study showed that a methane leak rate of greater than 3 percent would result in no immediate climate benefits from retiring coal-fired power plants in favor of natural gas power plants.

[0010] One maj or cause of emissions at production sites is fugitive emissions. There are several potential sources of fugitive emissions throughout the oil and natural gas sector.

[0011] Fugitive emissions occur when connection points are not fitted properly or when seals and gaskets start to deteriorate. Changes in pressure or mechanical stresses can also cause components or equipment to leak. Potential sources of fugitive emissions include but are not limited to agitator seals, connectors, pump diaphragms, flanges, instruments, meters, open-ended lines, pressure relief devices, pump seals, valves, and improperly controlled liquid storage tanks.

[0012] Another source of methane emission from oil and gas processing equipment is pneumatic controllers. These controllers use the produced gas under pressure for actuation and are considered a major source of emissions. An EPA report indicated around 477,000 pneumatic controllers are in use at natural gas production sites in the United States. These CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) controllers are estimated to emit 334 Kg/yr. of methane (17.4 billion cubic feet (bcf) of methane), for an average of 4.2 scf/h of methane / device. They also release other pollutants which are present in the produced gas being used.

[0013] Other emission sources during production include but are not limited to pneumatic pumps and centrifugal and reciprocating compressors.

[0014] Gas powered pneumatic pumps are generally used at oil and natural gas production sites for methanol and chemical injection where electricity is not readily available, and they can be a significant source of emissions. Typically, these pumps include plunger pumps with a diaphragm or large piston on the gas end and a smaller piston on the liquid end. This enables a high discharge pressure with a varied but much lower pneumatic supply gas pressure.
Pneumatic diaphragm pumps are used widely in the onshore oil and gas sector to move larger volumes of liquids per unit of time at lower discharge pressures than chemical and methanol injection pumps. The usage of these pumps is episodic, including transferring bulk liquids such as motor oil, pumping out sumps, and circulation of heat trace medium at well sites in cold climates during winter months.

[0015] In a reciprocating compressor, emissions occur when natural gas leaks around the piston rod when pressurized natural gas is in the cylinder. Over time, during operation of the compressor, the rod packing system becomes worn and will need to be replaced to prevent excessive leaking from the compression cylinder. Emissions are today controlled by replacement of the compressor rod packing, replacement of the piston rod, and the refitting or realignment of the piston rod. Emissions from centrifugal compressors depend on the type of seal used: either "wet", which use oil circulated at high pressure, or "dry", which use a thin gap of high-pressure gas. Dry seals are much more efficient, but both result in the release of emissions.

[0016] The configuration of surface wellhead fluids processing equipment used by oil producers varies from basin to basin and from producer to producer. However, the current state of the art implementation usually involves three to five steps of separation which progressively transition from higher to lower pressure until the cmde pressure finally reaches atmospheric pressure in the local storage tanks. The wellhead fluid is usually choked back to between 80 and 450psi. The fluid enters a three-phase separator to separate the water, crude and wet gas.
In some basins, the separator is heated to drive more of the gas out of the crude. However, at CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 80-450psi there is still a lot of gas entrenched in the crude and there are liquids entrenched in the gas. After that initial separation the wet gas, which still contains some oil, is typically injected into the midstream gathering line and the crude goes to a lower pressure vessel to enable more gas to escape the liquid. That gas is then typically compressed and also injected into the midstream gathering line. The crude may than go to a vertical vessel called a vapor recovery tower (VRT) at an even lower pressure so that more gas can be separated from the crude. That gas is typically then compressed and injected into the gathering line. Last, the crude is typically dumped into atmospheric storage tanks where the last remining entrenched gases escape the crude. Those gases are typically collected by a specialty compressor called a Vapor Recovery Unit or VRU and either flared or injected into the gathering line.

[0017] Crude stored in the on-site storage tanks is typically either injected into a midstream crude gathering line through a Lease Automatic Custody Transfer (LACT) unit or is loaded periodically into truck or rail transports. The loading of the crude is also a source of emissions, as -thief hatches" are opened in the top of the tank which allows the release of evolved vapors from the head space of the tank and from the agitation of the crude during loading activities.
Also hydrocarbon vapors present in the transport and in the loading lines are displaced by the loaded crude, and these vapors are also typically released into the environment or may be routed to a combustor or flare.

[0018] Another source of well pad emissions is the flare. Gas is typically disposed of onsite in the U.S. either through combustion in an open tip flare (which is what is shown in most of the images of flaming oilfield flares in the media), or in a closed flare, called a combustor (which usually looks like a chimney or a barrel and does not typically have a visible flame). In ideal circumstances, the flare is used only for emergency situations where gas is produced but it cannot be evacuated. In that case, it is less hazardous and polluting to do a controlled burn of the gas rather than venting it. However, over the last decade, continuous flaring has become a routine part of unconventional oil production operations.

[0019] Modern flares combust between 95% to 99.8% of the gas and 0.2% to 5% of the gas escapes combustion releasing methane, Volatile Organic Compounds (VOCs), and other pollutants directly into the environment. Incomplete combustion in the flare also results in criteria pollutant emissions including but not limited to VOCs, nitrogen oxides primarily nitric CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) oxide and nitrogen dioxide (N0x), Sulfur oxide (S0x), carbon monoxide and particulate matter.

[0020] When there is a need to perform maintenance on the oil production equipment, for safety reasons, any hydrocarbon inventory contained within that equipment is typically evacuated to a standby tank. That tank is usually outside the emission control regime, resulting in venting of the process gases resulting in emissions.

[0021] Additional sources of emissions are from upset conditions such as the release of pressure relief valves (which can occur during process upsets and other occasional operational events) and gas venting during maintenance of the gas processing equipment, which can include but is not limited to the purging of lines, knock out vessels and storage tanks.

[0022] Perhaps the least understood source of emissions results from the interdependency among nearby well pads and between each pad and the midstream company.
Usually, there is a gas evacuation pipeline that connects multiple pads to the midstream line.
The pipeline has a capacity that is determined by its diameter and its operating pressure.
However, because of the huge variability in production from unconventional oil well sites, there is typically a chronic shortage of evacuation capacity. The midstream does not want to invest in a very large pipeline that, after the connected shale wells go through their rapid decline curve will be oversized in as little as a year later. As a result, when a new pad is brought online, it's very high initial production of gas can overwhelm the gathering line capacity, forcing many of the other nearby pads that are connected to that line to shut in or to flare.
Since there is most often no communication among pads, the sudden disappearance of evacuation capacity surprises the producers. This upset condition can result in massive flaring on the nearby pads until the producers react and can curtail their production to fit the available capacity. The same circumstance can occur in other situations including but not limited to when the midstream company needs to perform maintenance on the pipeline, when they remove blockages or slugs from the line, or when they shut the pipeline down due to maintenance at the gas processing facility.

[0023] A typical wellhead fluid will traverse between 5 and 10 "unit operations" on the pad. Each one of these unit operations may have components that add to site complexity and can result in emissions, including but not limited to isolation valves, actuators, knockout vessels, retention vessels, overflow and blowdown connections, and storage.
Many of these CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) unit operations may involve or have a connection to systems including but not limited to compressors, metering skids, combustors or flares and other ancillary production or safety equipment.

[0024] In total, the number of point sources of fugitive emissions on a typical pad can easily exceed 100 independent point sources. Although each of these fugitive emission sources may emit a very small amount of methane, other hydrocarbons, and pollutants, the cumulative environmental impact across all the wells and all the pads in each basin can be massive.

[0025] The sheer number of point emission sources and the diminutive nature of each of the emissions makes the issue of fugitive emissions reduction from oil field surface infrastructure a very difficult problem to solve.

[0026] Accordingly, there is a need for a method to reduce the emissions from oil and gas production and transportation. A solution to at least one of the aforementioned problems with regard to current emissions from production and transportation of oil and gas underscores the need for a method to reduce the emissions of methane, other hydrocarbons, criteria pollutants, and non-clitetia pollutants.
BRIEF SUMMARY OF THE INVENTION

[0027] The instant invention in one form is directed to a method and system for eliminating emissions from crude production facilities through the stabilization of crude oil at pressure.

[0028] In a first implementation of the invention, the method involves the reduction of the total emissions from oil production facilities vs traditional processing methods through the removal of entrained volatile gases from the crude oil (stabilizing the crude) and the introduction into that stabilized crude of hydrocarbon liquid molecules which would otherwise be evacuated from the production site entrained within the produced gas. By performing this stabilization at pressure, a much simpler system can be utilized versus CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) traditional processing methods, which will reduce the need for combustion sources on the pad and significantly reduce fugitive and other emissions.

[0029] One system which can be used to achieve this method is a comprehensive end-to-end solution for surface well site crude and gas conditioning with minimized emissions.

[0030] The system separates wellhead fluids into streams which could include but are not limited to water, stabilized crude, propane rich NGLs, and lean residue gas.

[0031] The system consists of, but is not limited to, an integrated three-phase separator, a reboiler, a stabilization column, an overhead condenser with a dynamic reflux rate, and a three-phase reflux drum.

[0032] The conditioned crude may or may not be subcooled after exiting the system.

[0033] A feedback loop may or may not be used to prevent fluids from entering the system when the midstream evacuation line is unable to accept gas.

[0034] If the crude is not sufficiently stabilized before leaving the system it may or may not be recycled within the system for further conditioning.

[0035] The operating pressure of the system may or may not be higher than the midstream gas evacuation pressure. If it is higher, this may eliminate the need for gas compression on the pad. If it is lower, this may reduce the need for gas compression on the pad vs traditional processing systems.

[0036] The instant invention is furthermore a method and a system for stabilizing crude at higher than atmospheric pressure with the goal of reducing total emissions from oil production facilities comprising:
a. One or more separation systems to separate the hydrocarbon liquids, hydrocarbon gases and water, CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) b. One or more vertical separation systems utilizing a reboiler, c. Optionally one or more reflux systems to further separate entrenched gases from the liquid phase, d. Optionally one or more systems that collect the overhead gases from the first and second systems and cool it to near ambient temperature, e. Optionally one or more systems that separate the condensed liquids from the third system into water, condensed hydrocarbons liquid and gaseous hydrocarbons, and f. An instrumentation and control system.

[0037] These and other objects, features, and advantages of the present invention will become more readily apparent from the attached drawings and the detailed description of the preferred embodiments, which follow.
BRIEF DESCRIPTION OF THE DRAWINGS

[0038] A further understanding of the nature and advantages of particular embodiments may be realized by reference to the remaining portions of the specification and the drawings, in which like reference numerals are used to refer to similar components. When reference is made to a reference numeral without specification to an existing sub-label, it is intended to refer to all such multiple similar components.

[0039] Fig. 1 shows a process flow diagram for the system, which is one implementation of the method.

[0040] Fig. 2 shows a traditional oil production facility.

[0041] Fig. 2A shows the tank farm area of Fig. 2

[0042] Fig. 2B shows the separator area of Fig. 2 CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26)

[0043] Fig. 2C shows the well head area of Fig. 2

[0044] Fig. 3 shows a schematic diagram of a traditional oil production facility.

[0045] Fig. 4 shows a schematic diagram for a system which is one implementation of the method.

[0046] Corresponding reference characters indicate corresponding parts throughout the several views. The exemplifications set out herein illustrate embodiments of the invention and such exemplifications are not to be construed as limiting the scope of the invention in any manner.
DETAILED DESCRIPTION

[0047] While various aspects and features of certain embodiments have been summarized above, the following detailed description illustrates a few exemplary embodiments in further detail to enable one skilled in the art to practice such embodiments. The described examples are provided for illustrative purposes and are not intended to limit the scope of the invention.

[0048] In the following description, for the purposes of explanation, numerous specific details are set forth in order to provide a thorough understanding of the described embodiments. It will be apparent to one skilled in the art however that other embodiments of the present invention may be practiced without some of these specific details.
Several embodiments are described herein, and while various features are ascribed to different embodiments, it should be appreciated that the features described with respect to one embodiment may be incorporated with other embodiments as well. By the same token however, no single feature or features of any described embodiment should be considered CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) essential to every embodiment of the invention, as other embodiments of the invention may omit such features.

[0049] In this application the use of the singular includes the plural unless specifically stated otherwise and use of the terms "and" and "or" is equivalent to "and/or," also referred to as "non-exclusive or" unless otherwise indicated Moreover, the use of the term "including,"
as well as other forms, such as "includes" and "included," should be considered non-exclusive. Also, terms such as "element" or "component" encompass both elements and components including one unit and elements and components that include more than one unit, unless specifically stated otherwise.

[0050] Lastly, the terms "or" and "and/or" as used herein are to be interpreted as inclusive or meaning any one or any combination. Therefore, "A, B or C" or "A, B and/or C"
mean "any of the following: A; B; C; A and B; A and C; B and C; A, B and C."
An exception to this definition will occur only when a combination of elements, functions, steps or acts are in some way inherently mutually exclusive

[0051] As this invention is susceptible to embodiments of many different forms, it is intended that the present disclosure be considered as an example of the principles of the invention and not intended to limit the invention to the specific embodiments shown and described.

[0052] The term stabilized crude or conditioned crude refers to crude that meets certain conditions such as a predefined Reed Vapor Pressure (RVP).

[0053] A stripping column is a tower similar to a stabilization column, but does not use an overhead condenser, reflux drum or reflux fluid.
CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26)

[0054] Overhead condenser is a type of heat exchanger that accepts gas from the top half of the fractionation column and chills it down causing entrenched water and heavier hydrocarbons to condense.

[0055] The terms emissions, or total emissions, when used herein, includes methane emissions, other hydrocarbon emissions, criteria pollutant emissions, non-criteria pollutant emissions, greenhouse gas emissions, and all other molecules emitted to the atmosphere from oil production facilities. When used herein, emissions refer to these different types of emissions, both collectively and individually.

[0056] Production fluid or wellhead fluid is the fluid mixture of oil, gas and water that flows to the surface of an oil well from a reservoir.

[0057] A three-phase separator is an oblong vessel with a weir inside. The vessel receives production fluid. The water is accumulated on one side of the weir. Liquid hydrocarbons float over the water and spill over the weir. Gaseous hydrocarbons leave the solution and exit at the top of the vessel.

[0058] A distillation column is a tower with media inside. Heat is provided at the bottom of the column and heats the liquid hydrocarbons. As they heat, the lighter hydrocarbon chains evaporate and flow to the top of the column. Heavier hydrocarbon chains flow to the bottom of the column. This process results in fractionation, or separation or conditioning of the hydrocarbon streams. The terms stabilization column, distillation column and fractionation column are used herein interchangeably.

[0059] Prior to a discussion of the preferred embodiment of the invention, it should be understood that the features and advantages of the invention are illustrated in terms of a system of the instant invention that separates wellhead fluids at pressure, into water, CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) stabilized crude, propane rich NGLs, and lean residue gas, by integrating a three-phase separator with a stabilization column, an overhead condenser with a dynamic reflux rate, and a three-phase reflux drum to minimize emissions of various gases. Therefore one should realize that many different embodiments are possible.

[0060] The method of the instant invention works at a pressure of 100psi to 600psi

[0061] The NGLs are produced at a pressure of 0psi to 600psi.

[0062] In one embodiment, the crude is flashed to atmospheric tanks.

[0063] The vapor pressure of a liquid NGLs stream from the process may range from 2 psi to 350 psi.

[0064] The temperature of the liquid NGLs from the present process may range from -40 C to 300 C.

[0065] In one embodiment, the gas from the three-phase separator is injected at the top of the fractionation column where it, together with the reflux gas from the top of the column, are refrigerated by an overhead condenser. The condensed water is rejected from the hydrocarbon liquids in a second specialized three-phase separator, called the reflux drum The gas leaves the reflux drum at pressure and contains mostly methane, ethane, and some propane. The hydrocarbon liquids from the reflux drum can either be recycled back into the column or can leave the system as a propane rich NGL stream.

[0066] In another embodiment, the decision of the amount of the liquids that should be reinjected into the column, called the reflux ratio, is dynamically controlled by the control system based on the desired specification of the product.

CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26)

[0067] In another embodiment, the liquid hydrocarbon stream from the three-phase separator is heated for proper stabilization at high pressure at the fractionation column, resulting in a hot crude stream containing only a small amount of volatile components.

[0068] In another embodiment, to finalize the stabilization, the crude is directed from the column to an ambient cooler The cooler sub cools the crude prior to directing it to the tank batteries, ensuring that no further gas separation will happen in the tank.

[0069] In another embodiment, a dynamic sampling system controls the crude's disposition. If the crude meets a specified vapor pressure, it is directed to the atmospheric storage tanks or to the product sales line either through or not through a LACT unit. If it is still too volatile, the system closes the inlet control valve, and the crude is recycled back to the three-phase separator.

[0070] In another embodiment, the system automatically adjusts the temperature of the reboiler to maximize the volume of the crude produced by maximizing the vapor pressure of the crude, while keeping it within the specified vapor pressure.

[0071] In another embodiment, the crude is injected directly to the crude gathering line through a LACT unit without going through local crude storage.

[0072] In another embodiment, the crude is injected directly into the crude gathering line directly from the system without going through a LACT unit.

[0073] In another embodiment, the dynamic controls offer flexibility to create the spec product Y-grade NGLs or L-grade NGLs.

[0074] In another embodiment, the dynamic controls offer flexibility to create non-spec NGLs.

CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26)

[0075] In another embodiment the NGLs are used as an enhanced oil recovery (EOR) stimulant.

[0076] In another embodiment, the NGLs are used as gas lift fluid.

[0077] In another embodiment, the NGLs are blended with the gas and sold to the gas midstream through a gathering line, or are trucked to market, or are used locally as fuel for power generation or other uses, or are flared.

[0078] In another embodiment of the invention, a means is provided to replace standard wellhead fluid processing equipment necessary during oil and gas production with a specialized integrated system optimized for processing and separating wellhead fluids into separate wastewater, oil, NGLs and natural gas streams as needed.

[0079] In another embodiment of the invention, the fractionation column has trays.

[0080] In another embodiment of the invention, the fractionation column has random packed media.

[0081] In another embodiment of the invention, in addition to the NGLs and residue gas, the fractionation column fractionates the crude further into refined products such as light naphtha, heavy naphtha, kerosene, diesel, vacuum gas oil and vacuum residue oil, or any combinations of this list, or into other refined products or product mixes.

[0082] In another embodiment, the fractionation column is divided into two or more columns to reduce the total height of the column, or to enable production of purity products, or for other purposes.

[0083] In another embodiment of the invention, the wellhead fluid is not subcooled before entering the system.

CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26)

[0084] In another embodiment of the invention, the stabilized crude is not subcooled after leaving the system.

[0085] In another embodiment of the invention, the overhead condenser uses a cooling system which could consist of, but is not limited to, an ambient air chiller or a mechanical refrigeration system

[0086] In another embodiment of the invention, a stripping column is used rather than a fractionation column, eliminating the need for the overhead condenser and reflux drum.

[0087] In another embodiment of the invention, the horizontal and vertical vessels are all mounted on a single skid or on multiple skids.

[0088] In another embodiment of the invention, the control system is connected to a central system and/or operations center through means including, but not limited to, a cellular communication link, or a satellite communication link, or a local area network.

[0089] In another embodiment of the invention, the central control system enables remote operators to monitor, control and manage several sites from one location.

[0090] In another embodiment of the invention, operators can prioritize the volume of production of each site.

[0091] In yet another embodiment of the invention, production from sites that are connected to the same gas evacuation pipeline can be dynamically prioritized to maximize the utility of the available evacuation capacity.

[0092] Referring to the Figures an example embodiment of the process is described below.

[0093] Figure 1, 2, 2A, 2B, 2C, 3 and 4 provides the tag names referred to herein.
CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26)

[0094] In one embodiment, the present invention relates to processing of wellhead fluid in an integrated system to increase crude volume while reducing emissions, including those from combustion sources.

[0095] The present invention stabilizes crude oil in a "single-step, high-pressure"
application, providing conditioned, sub-cooled crude oil to the tank batteries/on-site storage.
The conditioned, sub-cooled crude oil does not off-gas within tank batteries/on-site storage or low-pressure vessels, eliminating emissions from tank batteries/on-site storage due to off-gassing. The "single-step, high-pressure" conditioning consolidates most emissions into a single, high-pressure gas stream.

[0096] NGLs and natural gasolines are separated in a "single-step, high-pressure"
process. NGLs are optionally removed in the "single-step, high-pressure"
process as high-pressure liquid stimulant for reinjection downhole in an EOR process, improving well production. Natural gasolines are treated in the "single-step, high-pressure"
process and combined with stabilized crude oil.

[0097] "Single-step, high-pressure" treatment of crude oil increases overall crude oil production by selectively recovering butane and longer hydrocarbon chain components and combining them with the remaining crude.

[0098] In one preferred embodiment, the invention provides a "single-step, high-pressure" processing system shown in the drawings and a method for separation of crude oil, natural gas liquids, water, and associated gas by treatment of wellhead fluid in the following steps:

[0099] Wellhead fluid [100] containing a mixture of hydrocarbons and water flow through a pressure regulating valve [101] to stabilize system inlet flow.

CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 1001001 The pressure stabilized stream [102] enters the inlet three-phase separator [103]
which is equipped with coalescing technologies to reduce the settling time of the water/hydrocarbon emulsion. The discrete hydrocarbon stream spills over the weir and exits the separator.
1001011 Bulk water [135] is removed from the separator and is regulated through a control valve [136] for disposal [140].
1001021 The liquid hydrocarbon stream [104] exiting the inlet three-phase separator [103]
is regulated by a control valve [105] into a distillation column [107] which contains trays, or is a packed bed, or is of some other technology. Within the column, the hydrocarbon mixture is separated by component boiling point.
1001031 The gaseous hydrocarbons [117] exiting the inlet three-phase separator [103] are regulated through a control valve [118]. The gaseous hydrocarbons [119] may mix with the distillation column vapor [108] for further processing in the air-cooled condenser [110].
Alternatively, the gaseous hydrocarbons [119] may mix with the overhead phase separator gas [115] and exit the system [116] without further processing. The flow path is selected by two diverting valves [121 and 123].
1001041 The light hydrocarbons [108] exit the top of the column as a vapor.
The light hydrocarbons [109] enter an air-cooled condenser [110] to generate a partially condensed stream of hydrocarbons [111] near ambient temperature, which are then separated in an overhead phase separator [112].
1001051 The overhead phase separator vapor [113] that is leaving the overhead phase separator [112] is metered through a control valve [114] as conditioned gas [115].

CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 1001061 Bulk water [138] is removed from the overhead phase separator [112], metered through a control valve [139], and mixed with upstream bulk water [137] for disposal [140].
1001071 Hydrocarbons [125] exit the overhead phase separator [112] and are fed to a reflux pump [126]. The pump discharge [127] is metered by a valve [128] to maintain a steady reflux flow [129] to maintain product specification Excess hydrocarbon liquid [130]
is optionally fed to an injection pump [131] The liquid [132] is metered by a valve [133] to maintain a steady flow [134] and may be used in one of several ways, including but not limited to, increasing oil production in an EOR process.
1001081 Hydrocarbon liquid [141] leaving the bottom of the distillation column [107]
feeds a reboiler [142] to partially vaporize the liquid stream. The reboiler may be fired or electric or some other technology. Reboiler operating temperature is determined based on desired crude oil specifications, between 150 C and 400 C.
1001091 Reboiler vapor [143] exiting the reboiler [142] is returned to the distillation column [107] near the bottom of the column.
1001101 Reboiler liquids [144] exiting the reboiler [142] are metered through a control valve [146] and are cooled to near-ambient temperature with an air-cooled heat exchanger [148].
1001111 A slipstream from the cooled crude [149] is continuously analyzed with a vapor pressure analyzer to verify product quality.
1001121 If the cooled crude [149] meets the vapor pressure requirement, the crude product [150] flows through the product shutoff valve [151] and out of the system [152] to be stored on-site or injected directly into the crude gathering line.

CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) [00113] If the cooled crude []49] does not meet the vapor pressure requirement, the off-spec crude [153] is pumped [154] through the off-spec recirculation valve [156] to be reprocessed in the feed separator [103].
[00114] An example wellhead fluid stream is separated according to the described process.
Compositions, temperatures, pressures, and other relevant data are given below for major process streams. Major product streams include NGLs prior to pumping for well stimulation, residue gas for further processing or sale, conditioned crude, and wastewater for disposal.
This example demonstrates elimination of crude off-gassing in storage tanks, substantial recovery (98.7%) of C5+ components in crude product, and optional production of NGLs suitable for downhole injection in an EOR process or transportation.
[00115] Typical results are shown in Table 1 and Table 2, Wellhead Separator Separator Quantity UOM Fluid Separator Hydrocarbons Water Residue Gas (117) Gas (116)

(100) (104) (135) Vapor Fraction: 0.5057 1 0 0 Temperature: `C 65.56 65.56 65.56 65.56 38 Pressure: bara 25 25 25 25 Molar Flow: kgmol/h 823.9 416.7 388.8 18.42 486.3 Molecular Weight: kg/kgmol 59.8 31.34 92.27 18.02 32.53 Mass Flow: kg/h 49270 13060 35880 331.8 15820 Act. Volume Flow: m3/h 459.2 401.1 57.74 0.3396 594.4 Mass Density: kg/m3 . 107.3 32.56 621.4 976.9 26.62 mol Composition fraction CO2 0.3% 0.6% 0.1% 0.0%
0.5%
Nitrogen 0.2% 0.4% 0.0% 0.0%
0.3%
H20 2.9% 1.1% 0.3%
100.0% 0.4%
Methane 27.4% 48.8% 5.8% 0.0%
44.8%
Ethane 5.7% 8.2% 3.2% 0.0%
8.4%
Propane 24.1% 25.2% 24.0%
0.0% 29.0%
i-Butane 6.7% 4.8% 9.0% 0.0%
5.9%

SHEET (RULE 26) n-Butane ................................... : 16.0% .................. 10.0%
23.3% :0.0% 10.7%
i-Pentane 0.5% 0.2% 0.9% 0.0%
0.0%
n-Pentane 0.8% 0.2% 1.3% 0.0%
0.0%
:
n-Hexane 0.9% 0.1% 1.7% 0.0%
0.0%
C7+ 14.5% 0.3% 30.5% 0.0%
0.0%
Table 1 ll Condenser We Crude Conditioned Quantity UOM
Water (138) Stimulant (144) Crude (152) (127) Vapor Fraction: 0 0 0 0 Temperature: `C 38 38 259 49 Pressure: bara 18 18 20 1 Molar Flow: kgmol/h 3.589 155.5 160 160 Molecular Weight: kg/kgmol 18.02 49.87 158.1 158.1 Mass Flow: kg/h 64.66 7754 25290 25290 Act. Volume Flow: m3/h 0.06479 15.27 .. 49.03 35.27 Mass Density: kg/m3 998 507.7 515.8 717.2 mol Composition fraction CO2 0.0% 0.1% 0.0% 0.0%
Nitrogen : 0.0% 0.0% 0.0% 0.0%
H20 100.0% 0.1% 0.0% 0.0%
Methane 0.0% 5.1% 0.0% 0.0%
Ethane 0.0% 3.8% 0.0% 0.0%
Propane 0.0% 36.9% 0.1% 0.1%
i-Butane 0.0% 15.7% 1.4% 1.4%
n-Butane .................................. 0.0% 37.4% 13.7% 13.7%
CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 1-Pentane 0.0% 0.2% 2.3% 2.3%
n-Pentane 0.0% 0.3% 3.6% 3.6%
n-Hexane 0.0% 0.1% 4.4% 4.4%
C7+ 0.0% 0.2% 74.6% 74.6%

Table 2 1001161 As shown in Fig.4, in one embodiment, the invention provides a processing system shown in the drawings and a method for stabilizing crude oil at pressure by treatment of wellhead fluid in the following steps:
1001171 The wellhead fluids [401] may pass through zero, one or more pump(s) or compression device(s) [440] to increase its pressure to the operating pressure. Then the wellhead fluids may pass through zero, one or more flow control valves [443].
The flow control valve(s) [443] may be actuated by a control system or set manually or preset. The flow control valve(s) [443] may restrict flow into the system when one or more pressure sensors [444] indicated that there are gas evacuation constraints. The wellhead fluids are sent to zero, one or more phase separators [402, 406] These phase separators may be referred to as, but not limited to, allocation separator, HLPC separator, high pressure separator, test separator, heater treater, vertical separator, or bulk separator. The separator(s) [402, 406]
may collect wellhead fluid from one or more wellheads [401]. The separator(s) [402, 406]
may be two-phase separators or three-phase separators. The wellhead fluids may be chilled or heated by zero, one or more heaters or chillers or heat exchangers [441]. The heater(s), chiller(s) or heat exchanger(s) may be installed before phase separator(s) [402] or before bulk separator(s) [406] or after bulk separator(s) [406]. The separator(s) may produce three product streams: produced water stream(s) [403, 409], gaseous hydrocarbon stream(s) [405, SHEET (RULE 26) 407], and liquid hydrocarbon stream(s) [434]. The water stream(s) [403, 409]
may contain some amount of hydrocarbons. The gaseous hydrocarbon stream(s) [405, 407] may contain some amounts of liquid hydrocarbons and some water. The liquid hydrocarbon stream(s) may contain some amount of gaseous hydrocarbons and some water. The gaseous hydrocarbon stream(s) produced by the separator(s) [405, 407] may go directly to one or more gas sales, evacuation or use lines [419], or it may be routed to one or more column(s) [410]. The gaseous hydrocarbon stream(s) may be routed to the top half of the column(s) [410] or to one or more overhead condenser(s) [427]. The name "overhead condenser" does not necessary indicate that the condenser is physically overhead. It merely denotes that the hydrocarbon stream originates at the top half of the column. The overhead condenser(s) [413] chill the hydrocarbon stream and route it to zero, one or more reflux drum(s) [414].
The reflux drum(s) separate the hydrocarbon stream to two or more streams. A
gaseous hydrocarbon stream [430]. A water rich stream [415]. A liquid hydrocarbon stream [431].
The gaseous hydrocarbon stream [430] may contain some liquid hydrocarbons and some water. The water stream [415] may contain some liquid hydrocarbons and some gaseous hydrocarbons. The liquid hydrocarbon stream [431] may contain some gaseous hydrocarbons and some water. The gaseous hydrocarbon stream [430] may be routed to gas line(s) [419].
The liquid hydrocarbon stream [431] may be further divided [432] such that some of it will be routed to the top half of the column to be used as reflux fluid [416] and some of it will be routed out of the system [433]. The ratio between the amount of reflux fluid [416] and the amount that is routed out of the system [433], known as the reflux ratio, may be controlled by zero, one or more control valve(s) [432]. The reflux ratio may range between 0% (all the liquid hydrocarbon stream is routed out of the system) to 100% (all the liquid hydrocarbon CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) stream will be injected back into the column as reflux fluid). The reflux ratio may be determined dynamically by a control system or manually or be preconfigured.
The liquid hydrocarbon steam that is routed out of the system [433] may be blended with the gaseous hydrocarbon stream and routed to gas line(s) [419] or produced as an NGL
stream [418].
1001181 The liquid hydrocarbon stream [434] enters the column through one or more injection point(s) [435]. The injection location of the liquid hydrocarbon stream [434] may be determined dynamically by a control system or manually or be preconfigured.
The hydrocarbons at the bottom of the column are heated by a reboiler [426]. The reboiler can be controlled by a control system or set manually. The liquid hydrocarbon stream produced by the column [410] may be routed to zero, one or more sensor system(s) [436].
The sensor system(s) may check if the liquid hydrocarbon stream would meet the crude evacuation spec.
If the sensor system(s) deteimines that the liquid hydrocarbon stream would not meet crude evacuation spec, the liquid hydrocarbon stream may be routed back to the beginning of the process [437]. The routing of the off-spec liquid hydrocarbon stream may be controlled by a control system or manually or be preconfigured. The off-spec liquid hydrocarbon stream may be routed to the bulk separator [406] or to the phase separator [402] or to the column [410].
The routing of the off-spec liquid hydrocarbon stream may be determined dynamically by a control system or manually or be preconfigured.
1001191 The on-spec liquid hydrocarbon stream [438] may be cooled by zero, one, or more condenser(s) [425]. Cooling the liquid hydrocarbon stream "locks" the volatile hydrocarbons in the liquid phase producing stabilized crude that meets the crude evacuation specs. In one embodiment, the condenser [425] is implemented as a heat exchanger exchanging heat with the incoming stream [442]. This is known as an economizing heat CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) exchanger. The on-spec crude can be routed to evacuation [421] or to one or more onsite crude tank(s) [420], Even if routed to crude tank(s), the stabilized crude emissions would be minimal.
1001201 The water streams [403, 409, 412, 415] are routed to zero, one, or more water tank(s) [422] If the water stream is routed to water tank(s) [422], the emissions from the water [439] could be routed to one or more emission control device(s) [423].
The water can then be sent to disposal [424].
1001211 In one embodiment of the method, the system is collocated with one or more wellhead(s) on the same pad. In another embodiment, the wellhead(s) are located in a remote location and the wellhead fluid is piped into the system. In that embodiment, wellhead fluid from multiple locations may be routed into one system. In yet another embodiment, the wellhead(s) and the phase separator(s) are located in a remote location and one or more of the phase-separated streams are piped into the system. In that embodiment, phase-separated streams may be routed from multiple locations into the system.
1001221 Furtheiniore while referring now to the drawings Fig. 1 -4, and more particularly to Fig. 1, there is shown a system separates wellhead fluids, at pressure, into water, stabilized crude, propane rich NGLs, and lean residue gas by integrating a three-phase separator with a stabilization column, an overhead condenser with a dynamic reflux rate, and a three-phase reflux drum.
1001231 Fig. 1 shows a process schematic of an integrated system for well fluids processing.
1001241 In one embodiment, the process separation occurs by first adjusting the pressure of the fluids being produced from the well through a choke [100], then the fluids go through CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) a flow control valve that governs the amount of intake fluid to the system

[101]. Then the fluid [102] is injected into a specialized three-phase separator [103]. The three-phase separator separates the stream into three streams: wastewater [135], liquid hydrocarbons [104], and gaseous hydrocarbons [117].
1001251 In one embodiment, the three-phase separator [103] includes a coalescer to speed up phase separation of water and hydrocarbons.
1001261 In one embodiment, the gaseous hydrocarbons [117] exiting the inlet three-phase separator [103] are regulated through a control valve [118]. The gaseous hydrocarbons [119]
may mix with the distillation column vapor [108] for further processing in the air-cooled condenser [110]. Alternatively, the gaseous hydrocarbons [119] may mix with the overhead phase separator gas [115] and exit the system [116] without further processing. The flow path is selected by two diverting valves [121] and [123].
1001271 In one embodiment, the diverting valves [121] and [123] are continuously adjusted by the control system to ensure optimal product output.
1001281 In one embodiment, the light hydrocarbons [108] exit the top of the column as a vapor. This vapor [109] enters an air-cooled condenser [110] to generate a partially condensed stream of hydrocarbons [111] near ambient temperature, which are then separated in a three-phase reflux drum [112].
1001291 In one embodiment, vapor leaving the reflux drum [113] is metered through a control valve [114] as conditioned residue gas [115].
1001301 In one embodiment, the residue gas is injected into a midstream gathering line [116].
CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 1001311 In one embodiment, the water from the reflux drum [138] is removed through a control valve [139] and mixed with water from the main three-phase separator [137] for disposal [140].
1001321 In one embodiment, liquid hydrocarbon from the reflux drum [125] is fed to a reflux pump [126] The pump discharge [127] is governed by a valve [128] to maintain a steady reflux flow [129] to maintain product specification.
1001331 In one embodiment, excess hydrocarbon liquid [130] comprising mostly of ethane, propane, and butane (NGL) is fed to an injection pump [131] through a control valve [133] for reinjection to the wellhead [134] as miscible EOR fluid.
1001341 In one embodiment, the NGL stream [134] leaving the control valve [133] is pumped down hole to be used for the gas lift, where such gas lift may be achieved through use of one or more means including but not limited to use of a jet pump.
1001351 In another embodiment, that NGL fluid is stored in pressurized storage tanks on-site prior to transport to market.
1001361 In yet another embodiment, that NGL [134] is merged with the residue gas [116]
and injected into the midstream gathering line.
1001371 In one embodiment, the liquid hydrocarbon [104] from the main three-phase separator [103] is injected [106] into a reflux column [107]. A reboiler at the bottom of the column [142], heats the liquid leaving the bottom of the column [141] to partially vaporize the liquid stream.
1001381 In one embodiment, the reboiler may be one of several types, including but not limited to a fired burner and an electric reboiler.

CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 1001391 In one embodiment, the reboiler operating temperature is determined based on desired crude oil specifications, and would normally range between 100 C and 500 C.
1001401 In one embodiment, vapor exiting the reboiler [143] is returned to the bottom of the distillation column [107].
1001411 In one embodiment, hydrocarbon liquids (stabilized crude), exiting the reboiler [144] are metered through a control valve [146] and are cooled to near-ambient temperature through means including, but not limited to, an air-cooled heat exchanger [148].
1001421 In one embodiment, a slipstream from the sub-cooled stabilized crude [149] is continuously analyzed with a vapor pressure analyzer to verify product quality. If the cooled crude [149] does not meet the vapor pressure requirement, the off-spec crude [153] is pumped [154] through the off-spec recycling valve [156] to be reprocessed in the feed separator [103].
1001431 In one embodiment, if this crude [149] meets the vapor pressure requirement, the crude product [150] flows through the product shutoff valve [151] and out of the system [152] to on-site crude tanks or is injected into a crude gathering line through a LACT unit.
1001441 In one embodiment, the system automatically adjusts the temperature of the reboiler to maximize the volume of the crude produced by maximizing the vapor pressure of the crude, while ensuring it remains within the specified vapor pressure.
1001451 In another embodiment, the crude is injected directly to the crude gathering line through a LACT unit without going through local crude storage.
1001461 In yet another embodiment, the crude is injected directly into the crude gathering line directly from the system without going through a LACT unit.

CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 1001471 In another embodiment, the system comprises of a stripping column [107] rather than a distillation column, eliminating the need for the overhead condenser [110] and the reflux drum [112]. That embodiment will not be capable of generating a separate propane rich NGL stream.
1001481 In the preferred embodiment, the system will replace nearly all the equipment currently used on an oil pad. Particularly the system will replace equipment including but not limited to the heater treaters, mid-pressure separation vessels, mid pressure gas compressors, vapor recovery tower, vapor recovery unit (VRU compressor), gas sale compressors, knockouts, oxygen scrubbers and high-capacity flares. In the preferred embodiment, once the new system is installed on a pad, there will be no need for most combustion sources and routine venting and flaring. It will also eliminate most fugitive emissions.
The emissions reduction will be affected through implementation of different equipment than that which is traditionally used, thereby eliminating and reducing actual emissions sources vs the traditional approach, rather than through implementation of systems to control existing emissions sources by flaring.
1001491 Referring to Fig. 2, Fig. 2A, Fig. 2B and Fig. 2C which shows a pad with current state-of-the-art emissions mitigation. From one or more well heads (Well Head Area) the well head fluid is transported via one or more underground pipes to one or more high-low heated pressure separators [Z-1010 to Z-1190]. The high-pressure side of the separator typically operates at 100psi to 1,000psi. The low-pressure side of the separator typically operates at a pressure of 80psi to 180psi. In each one of these separators there is a burner that heats the crude. The burner is typically burning field gas. The gas from the high-pressure side of the high-low heated pressure separator goes directly to one or more gas sales lines CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) typically through one or more meters (sales meter). The gas from the low-pressure side of the high-low heated pressure separator(s) [Z-1010-Z-1190], goes to one or more compressor(s) [Z-2030], to be injected into one or more gas sales lines typically through one or more meters (sales meter). The crude optionally goes to one or more bulk crude separator(s) [Z-5400]
where the pressure is dropped further typically to under 80psi The gas released by the bulk separator(s) goes to one or more compressor(s) [Z-2020]. From that compressor(s) [Z-2020]
the gas is injected into one or more gas sales lines typically through one or more meters (sales meter). The crude from the bulk separator(s) optionally goes to one or more crude scrubber(s) [Z-5100] where the pressure is further dropped typically below 20psi. The gas from the crude scraper(s) [Z-5100] goes to one or more compressor(s) [Z-2010]
and from there to one or more gas sales lines typically through one or more meters (sales meter). The crude from the crude scraper(s) [Z-5100] optionally goes to one or more vapor recovery tower(s) [V-5300] where the pressure is dropped typically below 1 Opsi. The gas from the vapor recovery tower(s) [V-5300] goes to one or more compressor(s) [Z-2000]
and from there to one or more gas sales lines typically through one or more meters (sales meter). The crude from the vapor recovery tower(s) [V-5300] goes to one or more atmospheric tank(s) [TK-6100 ¨ TK-6450]. The vapors from the tank(s) go to one or more flares [FM-9100 ¨
FM-9600] where they are combusted. The tank(s) vapors may optionally go to an oxygen scrubber [V-5500 ¨ V-5501], and from there to one or more compressor(s) [Z-2000], and from there to one or more gas sales lines typically through one or more meters (sales meter).
Released produced water from each one of these steps is collected at each step and routed to atmospheric tanks [TK-6000 ¨ TK-6050]. The vapors from the water tanks go to the flares CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) [FM-9100 ¨ FM-9600]. From the tanks [TK-6100 - TK-6450] the crude is sent to the LACT
skid [Z-8000] for evacuation.
1001501 Fig. 2, Fig. 2A, Fig. 2B and Fig. 2C which shows the following combustion sources on the pad: One or more heated phase separators [Z-1010 to Z1190]. One or more compressors [Z-2000 to Z-2030]. One or more flares [FM-9100 ¨ FM-9600]. One or more generators [Z-2100]. In this embodiment there are 30 combustion sources on the pad. In addition, the pad depicted in Fig. 2, Fig. 2A, Fig. 2B and Fig. 2C contains almost 1,000 point sources of fugitive emissions.
1001511 In Fig. 2, Fig. 2A, Fig. 2B and Fig. 2C, when maintenance is performed on any of the pressurized vessels, pipes or other equipment, the gas in that equipment is vented to the atmosphere. The pressurized liquids are directed to the tanks [TK-6100 ¨ TK-6450] or to one or more standalone tank(s) [TK-6990] where the pressure is released, and the gas is vented to the atmosphere.
1001521 Referring to Fig. 3 describes the current state of the art of crude stabilization at oil production facilities. The wellhead fluids [301] are sent to one or more phase separator(s) [302]. The phase separator(s) produce two or three product streams. If it is a three-phase separator, it produces a water stream [312], a liquid hydrocarbon stream [304], and a gaseous hydrocarbon stream [303]. The produced water stream [312] contains some hydrocarbons.
The liquid hydrocarbon stream [304] contains some water. The gaseous hydrocarbon stream [303] contains some water. If it is a two-phase separator or a tank, it will produce a liquid stream [304] and a gaseous hydrocarbon stream [303]. Both these streams [304, 303] will contain some water. If the liquid hydrocarbon stream meets crude spec the crude can be sold [3 1 1]. If the liquid hydrocarbon stream does not meet crude spec, then the pressure is CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) reduced [309] and the liquid is injected into one or more additional phase separator steps at a lower pressure. This process repeats until the liquid hydrocarbon stream meets crude spec and is ready for sale. In each of the steps described above, some gaseous hydrocarbon stream [303] is released from the liquid phase. If the gaseous hydrocarbon stream is released at a pressure above the midstream evacuation pressure, then the gas is routed to gas sales [310]. If the gaseous stream is released at lower pressure, then if there is enough volume of gas that justifies the cost of running a compressor, or the volume is higher than what regulations allow to flare, the gas is compressed into the pipeline pressure [307] and is sold [310]. If the gaseous stream volume is insufficient to justify the cost of running a compressor or the volume is not high enough to generate emissions in excess of regulatory requirements, the gas is routed to one or more flares [308]. Similarly, if the gaseous stream contains contamination such as oxygen, it is also routed to flare(s) [305].
1001531 In a typical oil production site like that of Fig. 3, there would be 2-6 pressure reduction steps [309] to stabilize the crude.
1001541 Referring to Fig. 4 describes a system and method for crude stabilization at pressure to minimize emissions from oil production facilities. The wellhead fluids [401] may pass through zero, one or more pump(s) or compression device(s) [440] to increase its pressure to the operating pressure. Then the wellhead fluids may pass through zero, one or more flow control valves [443]. The flow control valve(s) [443] may be actuated by a control system or set manually or preset. The flow control valve(s) [443] may restrict flow into the system when one or more pressure sensors [444] indicated that there are gas evacuation constraints. The wellhead fluids are then sent to zero, one or more phase separators [402].
These phase separators may be referred to as, but not limited to, allocation separator, HI .13C

CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) separator, high pressure separator, test separator, heater treater, or vertical separator. The separator(s) [402] may collect wellhead fluid from one or more wellheads [401]. The separator(s) [402] may be a two-phase separator(s) or three-phase separator(s). The wellhead fluids may be chilled or heated by zero, one or more heaters or chillers or heat exchangers [441]. The heater(s), chiller(s) or heat exchanger(s) may be installed before phase separator(s) [402] or before phase separator(s) [406] or after phase separator(s) [406]. The separator(s) may produce three product streams: produced water stream(s) [403, 409], gaseous hydrocarbon stream(s) [405, 407], and liquid hydrocarbon stream(s) [434]. The water stream(s) [403, 409] may contain some amount of hydrocarbons. The gaseous hydrocarbon stream(s) [405, 407] may contain some amounts of liquid hydrocarbons and some water. The liquid hydrocarbon stream(s) [434] may contain some amount of gaseous hydrocarbons and some water. The gaseous hydrocarbon stream(s) produced by the separator(s) [405, 407] may go directly to one or more gas sales, evacuation or use line(s) [419], or it may be routed to one or more column(s) [410]. The gaseous hydrocarbon stream(s) may be routed to the top half of the column(s) [410] or to one or more overhead condenser(s) [427]. The name "overhead condenser" does not necessary indicate that the condenser is physically overhead. It merely connotates that the hydrocarbon stream originates at the top half of the column. The overhead condenser(s) [413]
chill the hydrocarbon stream and route it to zero, one or more reflux drum(s) [414]. The reflux drum(s) separate the hydrocarbon stream to two or more streams. A gaseous hydrocarbon stream [430]. A water rich stream [415]. A liquid hydrocarbon stream [431].
The gaseous hydrocarbon stream [430] may contain some liquid hydrocarbons and some water.
The water stream [415] may contain some liquid hydrocarbons and some gaseous hydrocarbons. The CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) liquid hydrocarbon stream [431] may contain some gaseous hydrocarbons and some water.
The gaseous hydrocarbon stream [430] may be routed to gas line(s) [419]. The liquid hydrocarbon stream [431] may be further divided [432] such that some of it will be routed to the top half of the column to be used as reflux fluid [416] and some of it will be routed out of the system [433]. The ratio between the amount of reflux fluid [416] and the amount that is routed out of the system [433], known as the reflux ratio, may be controlled by zero, one or more control valve(s) [432]. The reflux ratio may range between 0% (all the liquid hydrocarbon stream is routed out of the system) to 100% (all the liquid hydrocarbon stream will be injected back into the column as reflux fluid). The reflux ratio may be determined dynamically by a control system or manually or be preconfigured. The liquid hydrocarbon steam that is routed out of the system [433] may be blended with the gaseous hydrocarbon stream and routed to gas line(s) [419] or produced as an NGL stream [418].
[00155] The liquid hydrocarbon stream [434] enters the column through one or more injection point(s) [435]. The injection location of the liquid hydrocarbon stream [434] may be determined dynamically by a control system or manually or be preconfigured.
The hydrocarbons at the bottom of the column are heated by a reboiler [426]. The reboiler can be controlled by a control system or set manually. The liquid hydrocarbon stream produced by the column [410] may be routed to zero, one or more sensor system(s) [436].
The sensor system(s) may check if the liquid hydrocarbon stream would meet the crude evacuation spec.
If the sensor system(s) determines that the liquid hydrocarbon stream would not meet crude evacuation spec, the liquid hydrocarbon stream may be routed back to the beginning of the process [437]. The routing of the off-spec liquid hydrocarbon stream may be controlled by a control system or manually or be preconfigured. The off-spec liquid hydrocarbon stream may CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) be routed to the bulk separator [406] or to the phase separator [402] or to the column [410].
The routing of the off-spec liquid hydrocarbon stream may be determined dynamically by a control system or manually or be preconfigured.
1001561 The on-spec liquid hydrocarbon stream [438] may be cooled by zero one or more condenser(s) [425]. Cooling the liquid hydrocarbon stream "locks" the volatile hydrocarbons in the liquid phase producing stabilized crude that meets the crude evacuation specs. In one embodiment, the condenser [425] is implemented as a heat exchanger exchanging heat with the incoming stream [442]. This is known as an economizing heat exchanger. The on-spec crude can be routed to evacuation [421] or to one or more onsite crude tank(s) [420]. Even if routed to crude tank(s), the stabilized crude emissions would be minimal.
1001571 The water streams [403, 409, 412, 415] are routed to zero, one or more water tank(s) [422]. If the water stream is routed to water tank(s) [422], the emissions from the water [439] could be routed to one or more emission control device(s) [423].
The water can then be sent to disposal [424].

Table 3 is a greenfield sample that reflects the state points on Fig. 4.
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S N61 :.,.s.: 5.) 1.1D..i. ¶,:N.,4.-1 8 :.,E;4iLiLiOliWi:...........:3:AtEL,:ai.A.:.:M.Zii Table 3 1001591 In one embodiment of the method, the system is collocated with one or more wellhead(s) on the same pad. In another embodiment, the wellhead(s) are located in a remote SHEET (RULE 26) location and the wellhead fluid is piped into the system. In that embodiment, wellhead fluid from multiple locations may be routed into one system. In yet another embodiment, the wellhead(s) and the phase separator(s) are located in a remote location and one or more of the phase-separated streams are piped into the system. In that embodiment, phase-separated streams may be routed from multiple locations into the system 1001601 The instant invention is furthermore a method and a system for stabilizing crude at higher than atmospheric pressure with the goal of reducing total emissions from oil production facilities comprising of:
a. One or more separation systems to separate the hydrocarbon liquids, hydrocarbon gases and water, b. One or more vertical separation systems utilizing a reboiler, c. Optionally one or more reflux systems to further separate entrenched gases from the liquid phase, d. Optionally one or more systems that collect the overhead gases from the first and second systems and cool it to near ambient temperature, e. Optionally one or more systems that separate the condensed liquids from the third system into water, condensed hydrocarbons liquid and gaseous hydrocarbons, and f. An instrumentation and control system.
1001611 The method of the instant invention where the goal is to stabilize the crude while minimizing total emissions including fugitive emissions, combustion sources, criteria pollutants, venting, flaring and other greenhouse gas and hydrocarbon emissions, from oil production facilities.
CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 1001621 The method of the instant invention where the goal is to enable a simpler permitting process for new and old oil production facilities by reducing the need to control/flare/combust tank vapors and by reducing other sources of emissions.
1001631 The method of the instant invention where its goal is to stabilize the crude to maximize crude oil volume at or below the maximum allowable vapor pressure 1001641 The method of the instant invention where it can produce four streams:
produced water, stabilized crude, optional NGL rich liquid or gas, and residue gas rich in methane and ethane.
1001651 The method of the instant invention where the system processes wellhead fluid from multiple wellheads.
1001661 The method of the instant invention where the system processes wellhead fluid from wellheads from multiple well pads.
1001671 The method of the instant invention where a compression system or a pump is added to increase the pressure of the fluids from the well.
1001681 The method of the instant invention where the wellhead fluid first enters an initial phase separator, such as a pre-well separator or an allocation separator, or a test separator, in front of the main horizontal separator.
1001691 The method of the instant invention where the initial phase separator receives the wellhead fluid from one well and the main phase separator and vertical separator process the output of the initial phase separators from multiple wellheads, for bulk processing.
1001701 The method of the instant invention where the vertical phase separator is a distillation column.

CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 1001711 The method of the instant invention where the vertical phase separator is a stripping column.
1001721 The method of the instant invention where the gaseous streams produced from the horizontal phase separator(s) and vertical separator are combined.
1001731 The method of the instant invention where the gaseous streams produced from the phase separator(s) and vertical separator are chilled by an overhead condenser. The condensed liquid hydrocarbon fluid is accumulated in a reflux drum.
1001741 A method of the instant invention where a portion of the liquid hydrocarbon fluid accumulated in the reflux drum is used as a reflux fluid in the distillation column.
1001751 The method of the instant invention where the gaseous streams produced from the phase separator(s) are not combined with the distillation column gas, but rather the gaseous stream from the phase separator(s) can be used for, but is not limited to, injection into a midstream sales line, for power generation, as fuel for heating, for gas lift, for EOR, and/or sent to flare.
1001761 The method of the instant invention where the fluids entering the system are pre-cooled. The cooling system is selected from, but not limited to, an air-cooled heat exchanger, a water-cooled heat exchanger, and a mechanical refrigeration system.
1001771 The method of the instant invention where the fluids entering the system are not pre-cooled.
1001781 The method of the instant invention where the fluids entering the system are pre-heated. The heating system is selected from, but not limited to, an economizer heat exchanger(s), an electric heater(s), or a gas fired heater(s).

CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 1001791 The method of the instant invention where the separation system to separate the three streams: produced water, liquid hydrocarbons and gaseous hydrocarbons, is a heater treater or three phase separator which may be of vertical or horizontal type.
1001801 The method of the instant invention where a portion of the gas output stream is used in one or more of several means, but not limited to, being sent to one or more sales lines, or is used for distillation column heating, or is used for fuel for power generation, or is used for gas lift or is used for EOR, or sent to flare.
1001811 The method of the instant invention where an overhead cooling condenser is used where the cooling system employs, but is not limited to, an air-cooled partial condenser with electrically driven fan(s) and finned tubing in its construction, or where the cooling system employs a mechanical refrigeration system.
1001821 The method of the instant invention where said separation system is a three-phase-separator which is a pressure vessel made specifically to efficiently separate water and hydrocarbon mixtures into distinct steams.
1001831 The method of the instant invention where the NGL fluid stream is an off-spec product that is neither Y-Grade NGL fluid nor L-Grade NGL
1001841 The method of the instant invention where the NGL fluid stream is spec product such as Y-Grade NGL fluid or L-Grade NGL fluid.
1001851 The method of the instant invention where the NGL fluid stream contains trace amounts (<10%) of condensate.
1001861 A method of the instant invention where the separator and the distillation column are integrated on the same skid.

CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 1001871 A method of the instant invention where the separator and the distillation column are not integrated on the same skid.
1001881 A method of the instant invention where the separator and the distillation column are integrated in a single vessel.
1001891 A method of the instant invention where the separator and the distillation column are not integrated in a single vessel.
1001901 A method of the instant invention where the separator and distillation column are not skid mounted.
1001911 The method of the instant invention where the horizontal separation is a three-phase separator.
1001921 The method of the instant invention where the horizontal separation is a three-phase separator with a large crude accumulation side that can be used as a reservoir for the reflux system.
1001931 The method of the instant invention where the horizontal separation contains a coalescer, 1001941 The method of the instant invention where the vertical system is selected from, but not limited to, a random pack column, or a tray column, or a valve tray column or a bubble cap column, or a sieve column.
1001951 The method of the instant invention where membrane separation is used instead of a column.
1001961 The method of the instant invention where the input to the column can be diverted to different locations along the column to optimize yield.

CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 1001971 The method of the instant invention where the column is split into multiple columns.
1001981 The method of the instant invention where a fractionation column also fractionates the crude and gas into multiple components.
1001991 The method of the instant invention where multiple fractionation columns fractionate the crude and gas into crude components.
1002001 The method of the instant invention where the crude is heated by a direct fire heater.
1002011 The method of the instant invention where the crude is heated by an electric heater.
1002021 The method of the instant invention where the crude is heated by some other means than by a direct fire heater or by an electric heater.
1002031 The method of the instant invention where the temperature the crude is heated to is dynamically controlled by the control system.
1002041 The method of the instant invention where the temperature the crude is heated to is dynamically controlled by the control system with the goal of maximizing the total crude production by optimizing the vapor pressure of the crude leaving the system.
1002051 The method of the instant invention where the residue gas is produced at pressure higher than the midstream evacuation pressure.
1002061 The method of the instant invention where the overhead condenser uses a mechanical refrigeration system.
1002071 The method of the instant invention where the overhead condenser uses an ambient air-cooling system CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 1002081 The method of the instant invention where the overhead condenser uses a water-cooling system.
1002091 The method of the instant invention where there is no overhead condenser and no reflux drum.
1002101 The method of the instant invention where the crude is sub-cooled by a cooler after leaving the column.
1002111 The method of the instant invention where the gas is sub-cooled by a cooler after leaving column.
1002121 The method of the instant invention where the stabilized crude is sampled for quality control, and if not meeting the required quality, it is recycled back into the system.
1002131 The method of the instant invention where the control system throttles the incoming wellhead fluids based on its ability to evacuate the crude and gas.
1002141 The method of the instant invention where the control system is remotely connected via a telecommunication network to a remote operator.
1002151 The method of the instant invention where the remote operator can control a large number of systems on different locations.
1002161 The method of the instant invention where the remote operator can prioritize production of one site over another based on the capacity of the evacuation pipeline.
1002171 The method of the instant invention where the control valves are actuated using instrument air or electric actuators.
1002181 The method of the instant invention where the produced crude is stored in onsite tanks.

CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 1002191 The method of the instant invention where the produced crude is directly injected into the crude midstream gathering line, bypassing the need for onsite tanks.
1002201 The method of the instant invention where the system measures the quality of the crude and pumps it directly into the crude midstream, bypassing the need for onside LACT
unit.
1002211 A single-step-high-pressure system increasing overall crude oil production by selectively recovering butane and longer hydrocarbon chain components and combining them with the remaining crude providing conditioned, sub-cooled crude oil comprising the steps where:
a. wellhead fluid containing a mixture of hydrocarbons and water flow through a pressure regulating valve to stabilize system inlet flow, b. the pressure stabilized stream enters the inlet three-phase separator which is equipped with coalescing technologies to reduce the settling time of the water/hydrocarbon emulsion. the discrete hydrocarbon stream spills over the weir and exits the separator, c. bulk water is removed from the separator and is regulated through a control valve for disposal, d. the liquid hydrocarbon stream exiting the inlet three-phase separator is regulated by a control valve into a distillation column which contains trays or is a packed bed or is of some other technology. Within the column, the hydrocarbon mixture is separated by component boiling point, e. the gaseous hydrocarbons exiting the inlet three-phase separator are regulated through a control valve, the gaseous hydrocarbons may mix with the CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) distillation column vapor for further processing in the air-cooled condenser, alternatively, the gaseous hydrocarbons may mix with the overhead phase separator gas and exit the system without further processing, the flow path is selected by two diverting valves, f the light hydrocarbons exit the top of the column as a vapor, the light hydrocarbons enter an air-cooled condenser to generate a partially condensed stream of hydrocarbons near ambient temperature, which are then separated in an overhead phase separator.
g. vapor leaving the overhead separator is metered through a control valve as conditioned gas, h. bulk water is removed from the separator, metered through a control valve, and mixed with upstream bulk water for disposal, i. hydrocarbon exits the separator and is fed to a reflux pump, the pump discharge is metered by a valve to maintain a steady reflux flow to maintain product specification. Excess hydrocarbon liquid is optionally fed to an injection pump for reinjection to the wellhead to increase oil production in an EOR process, j. hydrocarbon liquid leaving the bottom of the column feeds a reboiler to partially vaporize the liquid stream, the reboiler may be fired or electric, reboiler operating temperature is determined based on desired crude oil specifications, between 150 C and 400 C, k. vapor exiting the reboiler is returned to the bottom of the distillation column, CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) 1. liquids exiting the reboiler are metered through a control valve and are cooled to near-ambient temperature with an air-cooled heat exchanger, m. a slipstream from the cooled crude is continuously analyzed with a vapor pressure analyzer to verify product quality, n if the cooled crude meets the vapor pressure requirement, the crude product flows through the product shutoff valve to be stored on-site, or to be injected directly into the crude midstream pipeline, and, o. if the cooled crude does not meet the vapor pressure requirement, the off-spec crude is pumped through the off-spec recirculation valve to be reprocessed in the feed separator.
1002221 A method of the instant invention where a stripping column is used with no overhead condenser and no reflux drum.
1002231 Since many modifications, variations, and changes in detail can be made to the described embodiments of the invention, it is intended that all matters in the foregoing description and shown in the accompanying drawings be interpreted as illustrative and not in a limiting sense. Furthermore, it is understood that any of the features presented in the embodiments may be integrated into any of the other embodiments unless explicitly stated otherwise. The scope of the invention should be determined by the appended claims and their legal equivalents.
1002241 In addition, the present invention has been described with reference to embodiments, it should be noted and understood that various modifications and variations can be crafted by those skilled in the art without departing from the scope and spirit of the invention Accordingly, the foregoing disclosure should be interpreted as illustrative only and CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26) is not to be interpreted in a limiting sense. Further it is intended that any other embodiments of the present invention that result from any changes in application or method of use or operation, method of manufacture, shape, size, or materials which are not specified within the detailed written description or illustrations contained herein are considered within the scope of the present invention 1002251 Insofar as the description above and the accompanying drawings disclose any additional subject matter that is not within the scope of the claims below, the inventions are not dedicated to the public and the right to file one or more applications to claim such additional inventions is reserved.
1002261 Although very narrow claims are presented herein, it should be recognized that the scope of this invention is much broader than presented by the claim. It is intended that broader claims will be submitted in an application that claims the benefit of priority from this application.
1002271 While this invention has been described with respect to at least one embodiment, the present invention can be further modified within the spirit and scope of this disclosure.
This application is therefore intended to cover any variations, uses, or adaptations of the invention using its general principles. Further, this application is intended to cover such departures from the present disclosure as come within known or customary practice in the art to which this invention pertains and which fall within the limits of the appended claims.
CA 03173974 2022- 9- 29 SUBSTITUTE SHEET (RULE 26)

Claims

What is claimed is:

1. A method and a system for stabilizing crude at higher than atmospheric pressure with the goal of reducing total emissions from oil production facilities comprising:
a. one or more separation systems to separate the hydrocarbon liquids, hydrocarbon gases and water;
b. one or more vertical separation systems utilizing a reboiler;
c. optionally one or more reflux systems to further separate entrenched gases from the liquid phase;
d. optionally one or more systems that collect the overhead gases from the first and second systems and cool it to near ambient temperature;
e. optionally one or more systems that separate the condensed liquids from the third system into water, condensed hydrocarbons liquid and gaseous hydrocarbons; and f. an instrumentation and control system.

2. The system according to claim 1 where its goal is to stabilize the crude while minimizing total emissions including fugitive emissions, combustion sources, criteria pollutants, venting, flaring and other greenhouse gas and hydrocarbon emissions, from oil production facilities.

3. The system according to claim 1 where the goal is to enable a simpler permitting process for new and old oil production facilities by reducing the need to control/flare/combust tank vapors and by reducing other sources of emissions.

4. The system according to claim 1 where its goal is to stabilize the crude to maximize crude oil volume at or below the maximum allowable vapor pressure.

5. The system according to claim 1 where it can produce four streams: produced water, stabilized crude, optional NGL rich liquid or gas, and residue gas rich in methane and ethane.

6. The system according to claim 1 where the system processes wellhead fluid from multiple wellheads.

7. The system according to claim 1 where the system processes wellhead fluid from wellheads from multiple well pads.

8. The system according to claim 1 where a compression system or a pump is added to increase the pressure of the fluids from the well.

9. The system according to claim 1 where the wellhead fluid first enters an initial phase separator, such as a pre-well separator or an allocation separator, or a test separator, in front of the main horizontal separator.

10. The system according to claim 1 and claim 9 where the initial phase separator receives the wellhead fluid from one well and the main phase separator and vertical separator process the output of the initial phase separators from multiple wellheads, for bulk processing.

11. The system according to claim 1 where the vertical phase separator is a distillation column.

12. The system according to claim 1 where the vertical phase separator is a stripping column.

13. The system according to claim 1 where the gaseous streams produced from the horizontal phase separator(s) and vertical separator are combined.

14. The system according to claim 1 where the gaseous streams produced from the phase separator(s) and vertical separator are chilled by an overhead condenser. The condensed liquid hydrocarbon fluid is accumulated in a reflux drum.

15. A system according to claim 1 where a portion of the liquid hydrocarbon fluid accumulated in the reflux drum is used as a reflux fluid in the distillation column.

16. The system according to claim 1 where the gaseous streams produced from the phase separator(s) are not combined with the distillation column gas, but rather the gaseous stream from the phase separator(s) can be used for, but is not limited to, injection into a midstream sales line, for power generation, as fuel for heating, for gas lift, for EOR, and/or sent to flare.

17. The system according to claim 1 where the fluids entering the system are pre-cooled.
The cooling system is selected from, but not limited to, an air-cooled heat exchanger, a water-cooled heat exchanger, and a mechanical refrigeration system.

18. The system according to claim 1 where the fluids entering the system are not pre-cooled.

19. A single-step-high-pressure system increasing overall crude oil production by selectively recovering butane and longer hydrocarbon chain components and combining them with the remaining crude providing conditioned, sub-cooled crude oil comprising the steps where:
a. wellhead fluid containing a mixture of hydrocarbons and water flow through a pressure regulating valve to stabilize system inlet flow;
b. the pressure stabilized stream enters the inlet three-phase separator which is equipped with coalescing technologies to reduce the settling time of the water/hydrocarbon emulsion. The discrete hydrocarbon stream spills over the weir and exits the separator;
c. bulk water is removed from the separator and is regulated through a control valve for disposal;
d. the liquid hydrocarbon stream exiting the inlet three-phase separator is regulated by a control valve into a distillation column which contains trays or is a packed bed or is of some other technology. within the column, the hydrocarbon mixture is separated by component boiling point;
e. the gaseous hydrocarbons exiting the inlet three-phase separator are regulated through a control valve, the gaseous hydrocarbons may mix with the distillation column vapor for further processing in the air-cooled condenser, alternatively, the gaseous hydrocarbons may mix with the overhead phase separator gas and exit the system without further processing, the flow path is selected by two diverting valves;
f. the light hydrocarbons exit the top of the column as a vapor, the light hydrocarbons enter an air-cooled condenser to generate a partially condensed stream of hydrocarbons near ambient temperature, which are then separated in an overhead phase separator;
g. vapor leaving the overhead separator is metered through a control valve as conditioned gas;
h. bulk water is removed from the separator, metered through a control valve, and mixed with upstream bulk water for disposal;

i. hydrocarbon exits the separator and is fed to a reflux pump, the pump discharge is metered by a valve to maintain a steady reflux flow to maintain product specification. excess hydrocarbon liquid is optionally fed to an injection pump for reinjection to the wellhead to increase oil production in an EOR process;
j. hydrocarbon liquid leaving the bottom of the column feeds a reboiler to partially vaporize the liquid stream, the reboiler may be fired or electric, reboiler operating temperature is determined based on desired crude oil specifications, between 150 C and 400 C;
k vapor exiting the reboiler is returned to the bottom of the distillation column;
1. liquids exiting the reboiler are metered through a control valve and are cooled to near-ambient temperature with an air-cooled heat exchanger, m. a slipstream from the cooled crude is continuously analyzed with a vapor pressure analyzer to verify product quality;
n, if the cooled crude meets the vapor pressure requirement, the crude product flows through the product shutoff valve to be stored on-site, or to be injected directly into the crude midstream pipeline; and, o. if the cooled crude does not meet the vapor pressure requirement, the off-spec crude is pumped through the off-spec recirculation valve to be reprocessed in the feed separator,

20. A system according to claim 19 where a stripping column is used with no overhead condenser and no reflux drum.