Method and system for y-grade upgrader

Abstract

The invention relates to a processing system that converts an oilfield byproduct into more valuable and marketable commodity streams. To be specific, a method for treating unfractionated natural gas liquids (NGLs) known as Y-Grade to produce three (3) marketable commodity streams: 1) lean field gas for utility use or gas sales made up of methane (C1); 2) high-graded liquid solvent for dedicated usage in well stimulation treatments and miscible oil recovery operations, heavily weighted toward ethane, propane and butane (C2, C3 and C4); and 3) stabilized pentane plus (C5+) oil stream for direct oil sales. The invention can be used standalone or incorporated in a processing system receiving produced fluids from wells that have been treated with unfractionated NGLs for Enhanced Oil Recovery purposes.

Description

CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application is related to and claims priority under 35 U.S.C. § 119 (e) from U.S. Patent Application No. 63 / 751,178 filed Jan. 29, 2025, titled “Method and System for Y-Grade Upgrader,” the entire contents of which is incorporated herein by reference for all purposes.TECHNICAL FIELD

[0002] The present disclosure generally relates to the processing and separation of natural gas liquids.BACKGROUND and INTRODUCTION

[0003] The U.S. oil and natural gas industries have gone through a “renaissance” with a dramatic increase in oil and gas production and reserves. Technological improvements in hydraulic fracturing and horizontal drilling have unlocked enormous oil and natural gas resources from tight formations, such as shale. In conjunction with the rise in oil and natural gas production, U.S. production of natural gas liquids has also increased.

[0004] Natural gas liquids (NGLs) are a group of hydrocarbons that includes ethane, propane, normal butane, isobutane, normal pentane, iso-pentane, and a mixture of heavier hydrocarbons (C6+ and their respective isomers) commonly referred to as natural gasoline. Typically, NGLs are differentiated from one another by the number of carbon atoms in their molecular chain, with ethane frequently being referred to as C2, propane as C3, butane as C4, etc. NGLs have a wide variety of applications from specialized fuels (e.g., propane, butane) to petrochemical feedstocks for making products like plastic and fertilizers.

[0005] NGLs are extracted as byproducts in the production of natural gas and oil. Of these two sources, natural gas processing is by far the most significant, contributing over 90% of NGL production in 2016. When extracted from a well, natural gas is predominantly methane (C1) mixed with other hydrocarbons, many of which are NGLs, in addition to various impurities. In order for the natural gas to be marketable, the NGLs and impurities must be removed to meet pipeline and end user specifications; a process known as “conditioning”. The separated NGLs and impurities may then be discarded or sold to processors for further treatment and / or processing, commonly referred to as fractionation. Fractionation involves the process of separating an NGL stream into the individual pure products present within the NGL stream. The processors then market these products as “purity” products. In many cases, gas sales contracts limit an oil and gas producer's ability to extract NGL components with restrictions on certain types of technologies before delivering to the gas processor. This prevents producers from using these NGLs directly for enhanced oil recovery (EOR) processes and prevents them from maximizing the value of the heavier pentane plus (C5+) components that can be sold with the producer's oil stream.

[0006] A common term for the unseparated, unfractionated NGLs coming out of a gas conditioning plant is Y-Grade. Y-Grade may have a wide range of compositions depending on a number of factors related to the reservoir the gas is produced from. There is no single composition that defines Y-Grade universally and there is no specific end-user for Y-Grade in contrast with purity products such as ethane, propane, or butane. Because of this, Y-Grade is a relatively low value byproduct that requires additional processing to generate the component purity products for which a market does exist.

[0007] The recent rise in domestic US natural gas production has led to a rapid rise in Y-Grade production, stretching the capacity of the infrastructure for transporting and processing Y-Grade. As a result, producers are seeing lower and lower prices for their NGL (Y-Grade) production.

[0008] Producers often disclose the pricing they receive for their NGLs in their annual reports and typically report that the realized price for NGLs is on the order of 30% to 40% of realized price for their oil production. There is a similar differential in price that exists between Y-Grade and the fractionated pure components derived from Y-Grade such as but not limited to HD-5 or HD-10 propane and EN417 butane fuel.SUMMARY

[0009] In some aspects, the techniques described herein relate to a system for stabilizing Y-Grade natural gas liquids (NGL), including an input stream of unfractionated NGL. By pumping the input stream to a stabilization system including a random packed, trayed, or structured packed stabilization column, an NGL solvent stream is stabilized and produced from the input stream. The input liquid stream may descend through the packing material to also produce a stabilized crude oil stream at the base of the stabilization column. A heater of the stabilization system may heat the stabilized crude oil stream which is re-introduced to the base of the stabilization column. The heater vaporizes the lighter hydrocarbon components (predominantly propane (C3) and butane (C4)) out of the stabilized crude oil stream to produce a gaseous NGL solvent stream which travels up through the stabilization column and exits at the top of the stabilization column. The gaseous NGL solvent stream may be directed to ambient coolers for liquification, storage and possible re-introduction to the stabilization system through a reflux loop. Reflux of this predominantly C3 and C4 NGL solvent stream into the top of the stabilizer column may be used as needed to optimize performance of the stabilization column. A stabilized crude oil stream exiting the of the stabilizer column may be monitored to ensure the reid vapor pressure (RVP) of the stabilized crude oil stream meets a predetermined specification. If the RVP meets the predetermined specification, the stabilized crude oil stream may be cooled and transferred to storage, a pipeline, or any other export system. If the RVP of the stabilized oil stream does not meet the predetermined specification, some of the crude oil stream, may be recycled back through the heater and re-introduced at the base of the stabilization column to vaporize additional light ends to lower the RVP of the crude stream.

[0010] In some embodiments, the system may be installed onsite at a gas conditioning plant, and the input stream may include unfractionated NGL produced by the gas conditioning plant. In further embodiments, the NGL solvent stream may be injected into a well for enhanced oil recovery or be sold as a commodity product.

[0011] In further embodiments, the NGL solvent stream may include at least one of methane ethane, propane, and butane and the stabilized crude oil stream may include primarily pentane plus hydrocarbons.

[0012] In yet further embodiments, the system may further include a control system operable to measure a reid vapor pressure (RVP) of the stabilized crude oil stream and adjust a temperature and a pressure of the stabilization system to a second temperature and a second pressure when the measured RVP falls outside the predetermined range to obtain an RVP of the stabilized crude oil stream within the predetermined range. The control system may employ a machine learning and / or artificial intelligence (AI) algorithm to determine the second temperature and second pressure necessary to achieve the stabilized crude oil stream having an RVP within the predetermined range.

[0013] In some aspects, the system may further include a well fluid stream extracted from a production well, and a three-phase separator operable to separate the well fluid stream into a wet gas stream, a volatile oil stream, and a water stream, wherein the volatile oil stream is fed into the stabilization system.

[0014] According to other aspects, the techniques described herein relate to a method of processing unfractionated natural gas liquids (NGLs), including feeding an input stream including unfractionated NGLs to a stabilization column, the stabilization column including a random packing material within the stabilization column, separating, using the stabilization column, hydrocarbons having a molecular weight less than or equal to butane from the input stream to produce a gaseous NGL solvent stream and a crude oil stream, and stabilizing, using the stabilization column, the crude oil stream to produce a stabilized crude oil stream.

[0015] In some embodiments, the method may further include measuring a reid vapor pressure (RVP) of the stabilized crude oil stream; determining if the RVP of the stabilized crude oil stream falls outside of a predetermined range; and if the RVP falls outside of the predetermined range, heating the crude oil stream, then recycling some or all of the stabilized crude oil stream into the stabilization system to vaporize additional lighter components, allowing the crude oil stream to meet product specifications. The method may also further include determining, using a control system a required temperature and a required pressure of the stabilization column to obtain an RVP within the predetermined range for the recycled stabilized crude oil stream; and adjusting, using the control system, the stabilization column to operate at the required temperature and required pressure.

[0016] In further embodiments, the present method may also include injecting the condensed NGL solvent stream obtained from the input stream into a production well for enhanced oil recovery. In other embodiments, the method may further include feeding a well fluid stream extracted from a production well to a three-phase separator, separating, using the three-phase separator, the well fluid stream into a wet gas stream, a volatile oil stream, and a water stream, and feeding the volatile oil stream into the input stream into the stabilization column.BRIEF DESCRIPTION OF THE DRAWINGS

[0017] FIG. 1 is a process flow diagram depicting the Y-Grade upgrader system where the Y-Grade input source is an NGL storage tank designed to receive Y-Grade via tanker truck transportation.

[0018] FIG. 2A is a process flow diagram depicting the Y-Grade upgrader system where the input source is a Y-Grade pipeline and produces a stabilized crude oil stream, an NGL injectant stream of propane and butane, and an ethane gas stream.

[0019] FIG. 2B is a process flow diagram depicting the Y-Grade upgrader system where the input source is a Y-Grade pipeline and produces a stabilized crude oil stream and an NGL injectant stream of ethane, propane, and butane.

[0020] FIG. 3 is a process flow diagram depicting the Y-Grade upgrader system configured to receive Y-Grade supply from multiple gas conditioning plants as the Y-Grade input source.

[0021] FIG. 4 is a process flow where the Upgrader is incorporated in the NGL recycle system for EOR projects, treating both incoming Y-Grade (trucked or pipeline) as well as produced fluids from the oil outlet of the EOR project three phase separator.DETAILED DESCRIPTION

[0022] Certain aspects of this disclosure are provided below. Some of these aspects may be applied independently and some of them may be applied in combination as would be apparent to those of skill in the art. In the following description, for the purposes of explanation, specific details are set forth in order to provide a thorough understanding of aspects of the application. However, it will be apparent that various aspects may be practiced without these specific details. The figures and descriptions are not intended to be restrictive.

[0023] The ensuing description provides example aspects only and is not intended to limit the scope, applicability, or configuration of the disclosure. Rather, the ensuing description of the example aspects will provide those skilled in the art with an enabling description for implementing an example aspect. It should be understood that various changes may be made in the function and arrangement of elements without departing from the spirit and scope of the application as set forth in the appended claims.

[0024] The terms “exemplary” and / or “example” are used herein to mean “serving as an example, instance, or illustration.” Any aspect described herein as “exemplary” and / or “example” is not necessarily to be construed as preferred or advantageous over other aspects. Likewise, the term “aspects of the disclosure” does not require that all aspects of the disclosure include the discussed feature, advantage, or mode of operation.1. Overview

[0025] The present disclosure provides methods and systems for the conversion of oil field byproducts into more valuable and marketable commodity streams. In particular, the disclosure provides methods and systems for the treatment of unfractionated natural gas liquids (NGLs) known as Y-Grade to produce three marketable commodity streams: 1) a lean field gas stream primarily including methane (C1) for utility use or evacuation for further conditioning, (2) a high-graded liquid solvent stream heavily weighted toward ethane, propane and butane (C2, C3 and C4) for dedicated usage in well stimulation treatments and miscible oil recovery operations, and 3) a stabilized pentane plus (C5+) oil stream for direct oil sales. The RVP of the stabilized oil stream can be adjusted to maximize production through blending with overall production from the site, or it can be trucked to alternative sites for blending with lower API crude to raise the API gravity of the overall crude stream. The systems and methods may be implemented on a standalone basis or in a processing system receiving produced Y-Grade fluids from wells that have been treated with unfractionated NGLs for EOR purposes.

[0026] The NGL components in Y-Grade are ideal for use as a solvent for stimulating increased oil recovery in EOR operations. With conventional EOR operations, the cost of fractionated purity components such as ethane, propane, and butane generally make EOR operations using these components marginally economic. The oil and gas industry has recently identified novel EOR processes that do not require the use of purity products but can instead use various combinations of NGLs to effect very efficient improved oil recovery. By avoiding the use of purity NGL products in EOR operations, the economics of EOR projects are dramatically improved and hold the potential for a step change in the oil industry's application of EOR processes and hence the expected recovery efficiency in existing oil reservoirs. Therefore, the present methods and systems improve upon these processes by providing a means for the stabilization of Y-Grade obtained from any source to produce a utility gas stream, a crude oil stream, and a mixed NGL solvent stream that may be used in EOR operations with a higher economic efficiency and recovery efficiency. The present Y-Grade upgrader system further improves upon conventional systems and methods in that unlike the conventional EOR systems and methods, the Y-Grade upgrader accounts for the manner in which the Y-Grade is stored or obtained as well as the presence of impurities. Because of this, the present Y-Grade upgrader and EOR systems are not sensitive to impurities and can process unfractionated Y-Grade with varying composition, storage and transport conditions.

[0027] When NGLs are injected into oil wells as solvent in EOR operations the NGLs mix with the oil being produced and become part of the production stream extracted from the wells. EOR operations may involve continuous injection of NGLs using conventional floods, or, in the case of tight, unconventional reservoirs like shales, a cyclic injection and production scheme may be a more effective method. The injected NGLs that are extracted with the production stream are generally sold in the wet gas stream or in the oil stream unless they are purposefully recovered in the production treatment process. However, installing specialty equipment designed to recover these NGLs from the production stream for re-use / reinjection in the EOR project may provide more value to the operator than selling them in the production streams.

[0028] With these considerations in mind, the present systems and methods for a Y-Grade upgrader were specifically designed to efficiently and adaptively separate returned NGL solvent components from the producing well(s) production stream and separate for re-use as injectant in EOR processes.

[0029] The operating conditions of the Y-Grade upgrader are heavily dependent on an accurate estimate of the composition of the fluids produced from the wells in an EOR project. The composition of the oil in the EOR project is therefore a key design input for the Y-Grade upgrader. The Y-Grade upgrader can be adapted to effectively operate within a wide operating envelope to be adaptive to any changes in the input composition.

[0030] Reservoir simulation is the most common method used for estimating the composition of the production from an EOR project, however there is a wide range of uncertainty associated with the reservoir simulation output. Having a reservoir simulator calibrated to field test data is critical to this methodology. Integrating the output of the reservoir simulation to the inlet of the equipment process modelling provides the best range of design parameters for the Y-Grade upgrader.

[0031] Theoretical integrated modeling results indicate the produced fluids from miscible EOR projects are highly volatile, particularly the produced oil, making the solvent difficult to recover with standard oil and gas production equipment. This non-conventional mixture is not suited for conventional oil and gas production facilities. This hypothesis has been confirmed in multiple field trials, resulting in negative impacts to operators to deliver oil sales at contract reid vapor pressure (RVP) specifications. Field trials further confirmed the need for specially designed equipment with operating conditions and configuration significantly different from standard oilfield production operations.

[0032] Y-Grade liquids are generally trucked, railed or transported via pipeline to large scale fractionation facilities for separation into purity components for sale and distribution to end-users whether it be for domestic or industrial use. Transportation costs, particularly for trucking, significantly reduce the value received by a producer. Accessing Y-Grade closer to the producing source for use in EOR, drilling, frac fluid, and well treatment enables stabilization on site eliminating the need for pipeline and / or truck transportation to a fractionation facility, fractionation, and retransportation back to the field. Having Y-Grade stabilization on site therefore dramatically improves the project economics.

[0033] The composition of Y-Grade varies widely due to differences in reservoir fluid characteristics and conditioning methodology used. The principal components used for liquid solvents in EOR projects are heavily weighted toward ethane (C2), propane (C3) and butane (C4). When using the Y-Grade as an injected solvent for EOR processes, the Y-Grade obtained from the gas conditioning facility may be directly injected downhole or it may be initially treated by the presently disclosed Y-Grade upgrader. By treating the Y-Grade with the Y-Grade upgrader, the heavier pentane plus (C5+) components may be stabilized, leaving the lighter C2, C3, and C4 components for use as solvent. The separated C5+ components may then be sold as oil and the lighter C2-C4 components may be used as EOR solvent for injection into wells for EOR. The ability to separate these components in this way dramatically improves the economics and efficiency of EOR projects.

[0034] Specifically, the Y-Grade upgrader systems and methods presently disclosed may use mechanical techniques including pressure, contact surface area and heat, to separate Y-Grade mixtures into a marketable gas stream, a liquid solvent blend weighted to ethane (C2), propane (C3), and butane (C4) in addition to a sales oil stream of pentane plus (C5+) components.

[0035] Similar stabilization techniques may be applied to the fluids produced from wells in EOR projects where Y-Grade is employed as the miscible solvent in both conventional applications and unconventional cyclic (aka huff and puff) scenarios. Because the EOR produced fluids contain a large proportion of returned injected NGLs, particularly in a cyclic injection / production scheme, and the produced fluids are highly volatile. Treating this high volatility crude oil therefore requires stabilization under specific processing specifications / conditions to deliver upon the optimum reid vapor pressure (RVP) contractual requirements. The presently disclosed Y-Grade upgrader system and methods accomplish this by monitoring the RVP of the produced crude oil stream and adaptively adjusting the processing conditions according to account for the composition of the production stream.

[0036] While prior art systems and methods generally address the equipment and processes used at conventional gas processing / NGL plants to extract the natural gas liquids and impurities from a gas stream, conventional crude oil stabilizers are only “partial” stabilizers, meaning the crude oil produced will still require additional stabilization steps, consisting of storage, tankage, and vapor recovery systems. In contrast, the Y-Grade upgrader according to the present systems and methods is a “full” stabilizer, and does not require the additional stabilization steps.

[0037] Furthermore, while the use and recycle of purity NGL components for EOR operations as well as the direct use of Y-Grade as a miscible solvent in EOR operations have been explored within the oil and gas industry, a need still exists for a process and system capable of adaptively processing Y-Grade and well production streams to not only create a predominantly C2 / C3 / C4 product stream that is ideal for use as a solvent in EOR operations but also allow for improved capture and re-use of NGLs in liquid form for ongoing cyclical EOR processes.2. Definitions

[0038] Chemical species and materials useful in the presently disclosed systems and methods include those described herein in any phase, state, or form, as well as mixtures thereof, where applicable.

[0039] When introducing elements of the various embodiment(s) of the present disclosure, the articles “a”, “an”, “the”, and “said” are intended to mean that there are one or more of the elements. The terms “comprising”, “including” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.

[0040] The use of individual numerical values are stated as approximations as though the values were preceded by the word “about” or “approximately.” Similarly, the numerical values in the various ranges specified in this application, unless expressly indicated otherwise, are stated as approximations as though the minimum and maximum values within the stated ranges were both preceded by the word “about” or “approximately.” In this manner, variations above and below the stated ranges can be used to achieve substantially the same results as values within the ranges. As used herein, the terms “about” and “approximately” when referring to a numerical value shall have their plain and ordinary meanings to a person of ordinary skill in the art to which the disclosed subject matter is most closely related or the art relevant to the range or element at issue. The amount of broadening from the strict numerical boundary depends upon many factors. For example, some of the factors which may be considered include the criticality of the element and / or the effect a given amount of variation will have on the performance of the claimed subject matter, as well as other considerations known to those of skill in the art. As used herein, the use of differing amounts of significant digits for different numerical values is not meant to limit how the use of the words “about” or “approximately” will serve to broaden a particular numerical value or range. Thus, as a general matter, “about” or “approximately” broaden the numerical value. Also, the disclosure of ranges is intended as a continuous range including every value between the minimum and maximum values plus the broadening of the range afforded by the use of the term “about” or “approximately.” Consequently, recitation of ranges of values herein are merely intended to serve as a shorthand method of referring individually to each separate value falling within the range, unless otherwise indicated herein, and each separate value is incorporated into the specification as if it were individually recited herein.

[0041] The term “pentane plus” as used herein, refers to organic hydrocarbon compounds having five or more carbon atoms (C5+) per molecule that are present in produced fluids from natural gas and oil wells. The term may refer to organic molecules having a molecular weight heavier than butane (C4) and may include normal and iso-pentane (C5), hexanes (C6), heptanes (C7), octanes (C8), nonanes (C9), decanes (C10), and higher-carbon hydrocarbons, including their isomers and cyclic / aromatic species where present.

[0042] The term “Y-Grade” as used herein, refers to an unseparated, unfractionated natural gas liquids (NGL) stream produced by or obtained from a natural gas conditioning facility and comprising a multi-component hydrocarbon mixture that is not fractionated into purity products. The term may include varying amounts of methane (C1), ethane (C2), propane (C3), butanes (C4), pentanes (C5), and heavier hydrocarbons (C6+), and may further include impurities commonly associated with produced fluids and NGL handling (e.g., inert gases and acidic gases). Because Y-Grade is derived from reservoir-dependent produced fluids and processing / handling conditions, there is no single universal composition, and its composition may vary with storage and transport pressure.

[0043] The term “standard temperature and pressure” (STP) as used herein, refers to the temperature of 60° F. and a pressure of 14.7 psia. The term may refer to measurements that were determined at the standard temperature and pressure.

[0044] The term “natural gas liquid” (NGL) as used herein, refers to the mixture of hydrocarbons and associated organic components recovered from natural gas and / or associated gas that are separated from the methane-rich gas stream and that are liquid under specified surface processing, transport, or storage conditions (e.g., at or near ambient temperature at a pressure sufficient to maintain a liquid phase). Natural gas liquids typically comprise one or more of ethane (C2), propane (C3), butanes (C4), pentanes (C5), and heavier hydrocarbons (C6+), including normal and branched isomers and, where present, cyclic and aromatic hydrocarbons, and may be produced by cooling / condensation, cryogenic expansion, absorption, and / or other gas-processing recovery operations, with optional downstream fractionation into purity products or delivery as an unfractionated stream (e.g., mixed NGL or Y-grade). In some embodiments, NGLs may also contain trace amounts of non-hydrocarbon constituents carried with the recovered liquids (e.g., sulfur-containing organics, dissolved acid gases, or other trace contaminants), depending on reservoir composition and the recovery and treating conditions.3. Systems

[0045] The present disclosure provides for a highly efficient system for the conversion of Y-Grade (a byproduct of natural gas conditioning) into a plurality of commodity streams. Unfractionated Y-Grade may be fed to the present system which in turn generates a stabilized crude oil stream and a cost effective NGL solvent supply. The solvent supply may be employed in well stimulation treatment and / or Enhanced Oil Recovery (EOR) projects, generating immediate incremental production benefits. The present systems may be incorporated into EOR production facilities to treat the highly volatile fluids produced by the EOR projects, providing a stabilized crude oil and capturing the NGL components from the production stream for reuse / recycle in the ongoing EOR process.

[0046] Y-Grade may be defined by a variety of compositions, as it is highly dependent on the overall composition of the original reservoir fluids from which it was obtained. In the case of Y-Grade that is trucked from a gas conditioning facility, the Y-Grade must be able to remain in liquid form at pressures ranging from about 50 psi to about 250 psi at standard temperature. This condition dictates that trucked Y-Grade will typically have less than 1 mole % methane and less than about 15 mole % ethane. Y-Grade pipelines operate at higher pressures ranging from about 400 psi to about 600 psi, and can tolerate a higher percentage of volatile lighter components like ethane (C2) while maintaining the Y-Grade in liquid state. Table 1 provides an exemplary Y-Grade composition obtained from a storage tank of a gas processing plant in Texas.TABLE 1Exemplary trucked Y-Grade composition in mole % froma storage tank at a gas processing plant in Texas.ComponentMole %N20.00CO20.02C10.26C23.55C318.96IC411.40NC419.90IC511.23NC512.92C6+21.76100%

[0047] Low methane and ethane concentrations are typical of Y-Grade that is trucked due to the lower pressure at which it is maintained. However, higher methane and ethane concentrations may be tolerated where the Y-Grade fluids are evacuated using a pipeline due to the higher routine operating pressure of pipelines. For example, pipelines are routinely operated at pressures ranging from about 400 psi to about 600 psi range. An exemplary Y-Grade composition obtained from an NGL pipeline in Texas is provided in Table 2.TABLE 2Exemplary Y-Grade composition in mole% from a NGL Pipeline in Texas.ComponentMole %N20.00CO22.3C10.0C242.8C329.0IC410.0NC47.0IC52.1NC52.1NC63.7C7+100%

[0048] The economics of the present Y-Grade upgrader system are delivered through two key commodity products. The first of these products is a stabilized crude oil stream, which is the most significant. The second is a predominantly ethane, propane, butane NGL solvent stream, which may be sold for or used directly onsite for well treatments and / or as enhanced oil recovery injectant, or in blending with other crude oil streams.

[0049] According to some aspects, the present disclosure relates to a system for stabilizing and separating Y-Grade natural gas liquids that includes an input stream of unfractionated NGL and a stabilization system including a pump, a stabilization column, a heater, and a reflux loop. In some embodiments, the input stream may have a composition similar to the exemplary Y-Grade composition of Table 1 or Table 2. However, the input stream may be a Y-Grade stream including NGLs of any composition and is not restricted to the compositions of Tables 1 and 2. The input stream may include methane, ethane, propane, butane, and pentane plus, as well as any other impurities often found in Y-Grade.

[0050] In some applications, the input stream may have a temperature of about 32° F. to about 250° F. For example, the input stream may have a temperature of about 32° F. to about 50° F., about 32° F. to about 75° F., about 32° F. to about 100° F., about 32° F. to about 125° F., about 32° F. to about 150° F., about 32° F. to about 175° F., about 32° F. to about 200° F., about 32° F. to about 225° F., about 32° F. to about 250° F., about 50° F. to about 75° F., about 50° F. to about 100° F., about 50° F. to about 125° F., about 50° F. to about 150° F., about 50° F. to about 175° F., about 50° F. to about 200° F., about 50° F. to about 225° F., about 50° F. to about 250° F., about 75° F. to about 100° F., about 75° F. to about 125° F., about 75° F. to about 150° F., about 75° F. to about 175° F., about 75° F. to about 200° F., about 75° F. to about 225° F., about 75° F. to about 250° F., about 100° F. to about 125° F., about 100° F. to about 150° F., about 100° F. to about 175° F., about 100° F. to about 200° F., about 100° F. to about 225° F., about 100° F. to about 250° F., about 125° F. to about 150° F., about 125° F. to about 175° F., about 125° F. to about 200° F., about 125° F. to about 225° F., about 125° F. to about 250° F., about 150° F. to about 175° F., about 150° F. to about 200° F., about 150° F. to about 225° F., about 150° F. to about 250° F., about 175° F. to about 200° F., about 175° F. to about 225° F., about 175° F. to about 250° F., about 200° F. to about 225° F., about 200° F. to about 250° F., or about 225° F. to about 250° F. depending on the source of the input stream and external ambient temperatures. In other applications, the input stream may have a pressure of about 100 psi to about 600 psi prior to being fed to the top of the stabilization column. For example, the input stream may have a pressure of about 100 psi to about 150 psi, about 100 psi to about 200 psi, about 100 psi to about 250 psi, about 100 psi to about 300 psi, about 100 psi to about 350 psi, about 100 psi to about 400 psi, about 100 psi to about 450 psi, about 100 psi to about 500 psi, about 100 psi to about 550 psi, about 100 psi to about 600 psi, about 150 psi to about 200 psi, about 150 psi to about 250 psi, about 150 psi to about 300 psi, about 150 psi to about 350 psi, about 150 psi to about 400 psi, about 150 psi to about 450 psi, about 150 psi to about 500 psi, about 150 psi to about 550 psi, about 150 psi to about 600 psi, about 200 psi to about 250 psi, about 200 psi to about 300 psi, about 200 psi to about 350 psi, about 200 psi to about 400 psi, about 200 psi to about 450 psi, about 200 psi to about 500 psi, about 200 psi to about 550 psi, about 200 psi to about 600 psi, about 250 psi to about 300 psi, about 250 psi to about 350 psi, about 250 psi to about 400 psi, about 250 psi to about 450 psi, about 250 psi to about 500 psi, about 250 psi to about 550 psi, about 250 psi to about 600 psi, about 300 psi to about 350 psi, about 300 psi to about 400 psi, about 300 psi to about 450 psi, about 300 psi to about 500 psi, about 300 psi to about 550 psi, about 300 psi to about 600 psi, about 350 psi to about 400 psi, about 350 psi to about 450 psi, about 350 psi to about 500 psi, about 350 psi to about 550 psi, about 350 psi to about 600 psi, about 400 psi to about 450 psi, about 400 psi to about 500 psi, about 400 psi to about 550 psi, about 400 psi to about 600 psi, about 450 psi to about 500 psi, about 450 psi to about 550 psi, about 450 psi to about 600 psi, about 500 psi to about 550 psi, about 500 psi to about 600 psi, or about 550 psi to about 600 psi.

[0051] The input stream may be in fluid communication with the stabilization column of the system, such that the input stream is fed to the top of the stabilization column for stabilization. As the input stream descends through the stabilization column, the stabilization column may separate the input stream into two primary streams, an NGL solvent stream and a stabilized crude oil stream. In some embodiments, the stabilization column may include a bed of randomly packed packing elements arranged to define a plurality of tortuous vapor and liquid flow paths distributed throughout the cross section of the column. The packing elements may include metallic packing bodies having characteristic sizes of about 1 inch to about 3 inches. For example, the metallic packing bodies may have characteristic sizes of about 1.00 inch to about 1.25 inches, about 1.00 inch to about 1.50 inches, about 1.00 inch to about 1.75 inches, about 1.00 inch to about 2.00 inches, about 1.00 inch to about 2.25 inches, about 1.00 inch to about 2.50 inches, about 1.00 inch to about 2.75 inches, about 1.00 inch to about 3.00 inches, about 1.25 inches to about 1.50 inches, about 1.25 inches to about 1.75 inches, about 1.25 inches to about 2.00 inches, about 1.25 inches to about 2.25 inches, about 1.25 inches to about 2.50 inches, about 1.25 inches to about 2.75 inches, about 1.25 inches to about 3.00 inches, about 1.50 inches to about 1.75 inches, about 1.50 inches to about 2.00 inches, about 1.50 inches to about 2.25 inches, about 1.50 inches to about 2.50 inches, about 1.50 inches to about 2.75 inches, about 1.50 inches to about 3.00 inches, about 1.75 inches to about 2.00 inches, about 1.75 inches to about 2.25 inches, about 1.75 inches to about 2.50 inches, about 1.75 inches to about 2.75 inches, about 1.75 inches to about 3.00 inches, about 2.00 inches to about 2.25 inches, about 2.00 inches to about 2.50 inches, about 2.00 inches to about 2.75 inches, about 2.00 inches to about 3.00 inches, about 2.25 inches to about 2.50 inches, about 2.25 inches to about 2.75 inches, about 2.25 inches to about 3.00 inches, about 2.50 inches to about 2.75 inches, about 2.50 inches to about 3.00 inches, or about 2.75 inches to about 3.00 inches. In further embodiments, the packing elements may collectively define a void fraction of about 85% to about 95%. For example, the packing elements may collectively define a void fraction of about 85% to about 86%, about 85% to about 87%, about 85% to about 88%, about 85% to about 89%, about 85% to about 90%, about 85% to about 91%, about 85% to about 92%, about 85% to about 93%, about 85% to about 94%, about 85% to about 95%, about 86% to about 87%, about 86% to about 88%, about 86% to about 89%, about 86% to about 90%, about 86% to about 91%, about 86% to about 92%, about 86% to about 93%, about 86% to about 94%, about 86% to about 95%, about 87% to about 88%, about 87% to about 89%, about 87% to about 90%, about 87% to about 91%, about 87% to about 92%, about 87% to about 93%, about 87% to about 94%, about 87% to about 95%, about 88% to about 89%, about 88% to about 90%, about 88% to about 91%, about 88% to about 92%, about 88% to about 93%, about 88% to about 94%, about 88% to about 95%, about 89% to about 90%, about 89% to about 91%, about 89% to about 92%, about 89% to about 93%, about 89% to about 94%, about 89% to about 95%, about 90% to about 91%, about 90% to about 92%, about 90% to about 93%, about 90% to about 94%, about 90% to about 95%, about 91% to about 92%, about 91% to about 93%, about 91% to about 94%, about 91% to about 95%, about 92% to about 93%, about 92% to about 94%, about 92% to about 95%, about 93% to about 94%, about 93% to about 95%, or about 94% to about 95%.

[0052] In some applications, the bed of randomly packed packing elements provides a distributed surface area for vapor-liquid contact while simultaneously allowing upward vapor flow through interstitial spaces formed between adjacent packing elements. The randomized geometry disrupts preferential flow paths, reduces vapor channeling, and promotes repeated redistribution of liquid across the bed of randomly backed packing elements, thereby enhancing separation of light hydrocarbon components from the descending liquid of the input stream. In further applications, the use of random packing may improve phase disengagement and mass-transfer efficiency, resulting in a stabilized hydrocarbon stream having a reduced vapor pressure and improved compositional stability relative to stabilization columns lacking internal packing. In some embodiments, the randomly packed packing material may be a stainless steel alloy, carbon steel alloy, aluminum alloy, plastic, a ceramic, or a combination thereof.

[0053] In some alternative embodiments, the stabilization column may include a bed of structured packing elements. In some aspects, the structured packing elements may include a plurality of corrugated metallic sheets. The corrugated metallic sheets may be arranged in an ordered geometry to define a network of inclined, intersecting flow passages. In one embodiment, the corrugated metallic sheets may be stacked to form the structured packing elements that collectively define the packed height of the column. In some embodiments, the stacked corrugated metallic sheets form a plurality of discrete structured packing elements positioned adjacent to one another within the stabilization column. In some embodiments, the corrugated metallic sheets of adjacent packing elements may be oriented at different angular alignments to promote redistribution of vapor and liquid. Liquid from the input stream introduced at the top of the stabilization column flows downward by gravity along the inclined surfaces of the corrugated metallic sheets, while vapor is permitted to flow upward counter-currently through the open flow passages formed between corrugations of the stacked corrugated metallic sheets, thereby increasing interfacial contact and mass transfer efficiency. In some applications, the flow passages formed between the corrugations may be non-cylindrical and non-rectangular. In further applications, the flow passages formed between the corrugations may be distributed throughout a cross-section of the packing, and do not extend continuously from the top of the stabilization column to the bottom of the stabilization column, such that maldistribution and channeling are reduced. In some embodiments, surface features such as perforations, texturing, wire-mesh constructions, or a combination thereof may be employed on the surface of the stacked corrugated metallic sheets to enhance wettability and vapor-liquid interaction. In further embodiments, multiple packing elements may be vertically stacked to provide a desired separation performance within the stabilization column.

[0054] In some embodiments, the stabilization column may include a bed of structured packing elements that define one or more vertical flow channels distinct from inclined flow passages formed by the packing geometry. The vertical flow channels provide low-resistance pathways for upward vapor flow while surrounding structured packing promotes distributed liquid flow and vapor-liquid contact. By diverting a portion of vapor flow away from primary mass-transfer surfaces, localized vapor loading and liquid entrainment may be reduced, thereby improving phase disengagement and enhancing removal of light hydrocarbon components from a descending liquid stream to produce a stabilized hydrocarbon stream having reduced vapor pressure and improved compositional stability relative to stabilization columns employing structured packing alone. In some embodiments, the bed of structured packing elements may include about 2 to about 8 vertical flow channels. For example, the bed of structured packing elements may include about 2 to about 3, about 2 to about 4, about 2 to about 5, about 2 to about 6, about 2 to about 7, about 2 to about 8, about 3 to about 4, about 3 to about 5, about 3 to about 6, about 3 to about 7, about 3 to about 8, about 4 to about 5, about 4 to about 6, about 4 to about 7, about 4 to about 8, about 5 to about 6, about 5 to about 7, about 5 to about 8, about 6 to about 7, about 6 to about 8, or about 7 to about 8 vertical flow channels. In some aspects, the vertical flow channels may have a hydraulic diameter of about 2 inches to about 4 inches. For example, the vertical flow channels may have a hydraulic diameter of about 2.00 inches to about 2.25 inches, about 2.00 inches to about 2.50 inches, about 2.00 inches to about 2.75 inches, about 2.00 inches to about 3.00 inches, about 2.00 inches to about 3.25 inches, about 2.00 inches to about 3.50 inches, about 2.00 inches to about 3.75 inches, about 2.00 inches to about 4.00 inches, about 2.25 inches to about 2.50 inches, about 2.25 inches to about 2.75 inches, about 2.25 inches to about 3.00 inches, about 2.25 inches to about 3.25 inches, about 2.25 inches to about 3.50 inches, about 2.25 inches to about 3.75 inches, about 2.25 inches to about 4.00 inches, about 2.50 inches to about 2.75 inches, about 2.50 inches to about 3.00 inches, about 2.50 inches to about 3.25 inches, about 2.50 inches to about 3.50 inches, about 2.50 inches to about 3.75 inches, about 2.50 inches to about 4.00 inches, about 2.75 inches to about 3.00 inches, about 2.75 inches to about 3.25 inches, about 2.75 inches to about 3.50 inches, about 2.75 inches to about 3.75 inches, about 2.75 inches to about 4.00 inches, about 3.00 inches to about 3.25 inches, about 3.00 inches to about 3.50 inches, about 3.00 inches to about 3.75 inches, about 3.00 inches to about 4.00 inches, about 3.25 inches to about 3.50 inches, about 3.25 inches to about 3.75 inches, about 3.25 inches to about 4.00 inches, about 3.50 inches to about 3.75 inches, about 3.50 inches to about 4.00 inches, or about 3.75 inches to about 4.00 inches. In further aspects, the vertical flow channels may collectively define an open flow area of about 3% to about 15% of the cross-sectional area of the stabilization column. For example, the vertical flow channels may collectively define an open flow area of about 3% to about 6%, about 3% to about 9%, about 3% to about 12%, about 3% to about 15%, about 6% to about 9%, about 6% to about 12%, about 6% to about 15%, about 9% to about 12%, about 9% to about 15%, or about 12% to about 15% of the cross-sectional area of the stabilization column.

[0055] The initial operating conditions of the stabilization system may be determined and set according to a composition of the input stream as simulated by a control system. The control system may be operable to adjust the operating conditions of the stabilization system to account for any variance in input stream composition such that the system produces an NGL solvent stream and a stabilized crude oil stream that meets a predetermined standard. In some applications the predetermined standard may include an acceptable range for the reid vapor pressure (RVP) of the stabilized crude oil stream.

[0056] The operating conditions adjusted by the control system may include the temperature and the pressure of the stabilization column. In some embodiments, the stabilization column may be operated at a temperature of about 100° F. to about 800° F. depending on the composition of the input stream. For example, the stabilization column may be operated at a temperature of about 100° F. to about 150° F., about 100° F. to about 200° F., about 100° F. to about 250° F., about 100° F. to about 300° F., about 100° F. to about 350° F., about 100° F. to about 400° F., about 100° F. to about 450° F., about 100° F. to about 500° F., about 100° F. to about 550° F., about 100° F. to about 600° F., about 100° F. to about 650° F., about 100° F. to about 700° F., about 100° F. to about 750° F., about 100° F. to about 800° F., about 150° F. to about 200° F., about 150° F. to about 250° F., about 150° F. to about 300° F., about 150° F. to about 350° F., about 150° F. to about 400° F., about 150° F. to about 450° F., about 150° F. to about 500° F., about 150° F. to about 550° F., about 150° F. to about 600° F., about 150° F. to about 650° F., about 150° F. to about 700° F., about 150° F. to about 750° F., about 150° F. to about 800° F., about 200° F. to about 250° F., about 200° F. to about 300° F., about 200° F. to about 350° F., about 200° F. to about 400° F., about 200° F. to about 450° F., about 200° F. to about 500° F., about 200° F. to about 550° F., about 200° F. to about 600° F., about 200° F. to about 650° F., about 200° F. to about 700° F., about 200° F. to about 750° F., about 200° F. to about 800° F., about 250° F. to about 300° F., about 250° F. to about 350° F., about 250° F. to about 400° F., about 250° F. to about 450° F., about 250° F. to about 500° F., about 250° F. to about 550° F., about 250° F. to about 600° F., about 250° F. to about 650° F., about 250° F. to about 700° F., about 250° F. to about 750° F., about 250° F. to about 800° F., about 300° F. to about 350° F., about 300° F. to about 400° F., about 300° F. to about 450° F., about 300° F. to about 500° F., about 300° F. to about 550° F., about 300° F. to about 600° F., about 300° F. to about 650° F., about 300° F. to about 700° F., about 300° F. to about 750° F., about 300° F. to about 800° F., about 350° F. to about 400° F., about 350° F. to about 450° F., about 350° F. to about 500° F., about 350° F. to about 550° F., about 350° F. to about 600° F., about 350° F. to about 650° F., about 350° F. to about 700° F., about 350° F. to about 750° F., about 350° F. to about 800° F., about 400° F. to about 450° F., about 400° F. to about 500° F., about 400° F. to about 550° F., about 400° F. to about 600° F., about 400° F. to about 650° F., about 400° F. to about 700° F., about 400° F. to about 750° F., about 400° F. to about 800° F., about 450° F. to about 500° F., about 450° F. to about 550° F., about 450° F. to about 600° F., about 450° F. to about 650° F., about 450° F. to about 700° F., about 450° F. to about 750° F., about 450° F. to about 800° F., about 500° F. to about 550° F., about 500° F. to about 600° F., about 500° F. to about 650° F., about 500° F. to about 700° F., about 500° F. to about 750° F., about 500° F. to about 800° F., about 550° F. to about 600° F., about 550° F. to about 650° F., about 550° F. to about 700° F., about 550° F. to about 750° F., about 550° F. to about 800° F., about 600° F. to about 650° F., about 600° F. to about 700° F., about 600° F. to about 750° F., about 600° F. to about 800° F., about 650° F. to about 700° F., about 650° F. to about 750° F., about 650° F. to about 800° F., about 700° F. to about 750° F., about 700° F. to about 800° F., about 750° F. to about 800° F., or about 800° F. to about 800° F. Alternatively, the stabilization system may be operated at a temperature of about 200° F. to about 750° F., depending on the composition of the input stream. In further embodiments, the stabilization column may be operated at a pressure of about 100 psig to about 600 psig, depending on the composition of the input stream. For example, the stabilization column may be operated at a pressure of about 100 psig to about 150 psig, about 100 psig to about 200 psig, about 100 psig to about 250 psig, about 100 psig to about 300 psig, about 100 psig to about 330 psig, about 100 psig to about 350 psig, about 100 psig to about 400 psig, about 100 psig to about 450 psig, about 100 psig to about 500 psig, about 100 psig to about 550 psig, about 100 psig to about 600 psig, about 150 psig to about 200 psig, about 150 psig to about 250 psig, about 150 psig to about 300 psig, about 150 psig to about 330 psig, about 150 psig to about 350 psig, about 150 psig to about 400 psig, about 150 psig to about 450 psig, about 150 psig to about 500 psig, about 150 psig to about 550 psig, about 150 psig to about 600 psig, about 200 psig to about 250 psig, about 200 psig to about 300 psig, about 200 psig to about 330 psig, about 200 psig to about 350 psig, about 200 psig to about 400 psig, about 200 psig to about 450 psig, about 200 psig to about 500 psig, about 200 psig to about 550 psig, about 200 psig to about 600 psig, about 250 psig to about 300 psig, about 250 psig to about 330 psig, about 250 psig to about 350 psig, about 250 psig to about 400 psig, about 250 psig to about 450 psig, about 250 psig to about 500 psig, about 250 psig to about 550 psig, about 250 psig to about 600 psig, about 300 psig to about 330 psig, about 300 psig to about 350 psig, about 300 psig to about 400 psig, about 300 psig to about 450 psig, about 300 psig to about 500 psig, about 300 psig to about 550 psig, about 300 psig to about 600 psig, about 330 psig to about 350 psig, about 330 psig to about 400 psig, about 330 psig to about 450 psig, about 330 psig to about 500 psig, about 330 psig to about 550 psig, about 330 psig to about 600 psig, about 350 psig to about 400 psig, about 350 psig to about 450 psig, about 350 psig to about 500 psig, about 350 psig to about 550 psig, about 350 psig to about 600 psig, about 400 psig to about 450 psig, about 400 psig to about 500 psig, about 400 psig to about 550 psig, about 400 psig to about 600 psig, about 450 psig to about 500 psig, about 450 psig to about 550 psig, about 450 psig to about 600 psig, about 500 psig to about 550 psig, about 500 psig to about 600 psig, or about 550 psig to about 600 psig. In one particular example, the stabilization column may be operated at a pressure of about 100 psig to about 400 psig depending on the composition of the input stream. In some embodiments, the stabilization system may include a pump in communication with and operable to maintain a pressure of the stabilization column.

[0057] In some embodiments, the stabilization column may include a housing formed from a carbon steel-based alloy suitable for elevated temperature and pressure service, including low-alloy chromium-molybdenum steels. By way of example, the housing may be constructed from a chromium-molybdinum (Cr—Mo) alloy steel having enhanced creep resistance and a high-temperature strength sufficient for continuous operation at temperatures at or near approximately 800° F. in addition to internal pressures at or near approximately 600 psig, thereby maintaining structural integrity and pressure containment under sustained thermal and mechanical loading conditions.

[0058] As mentioned above, an important aspect of the present systems is the ability to simulate the composition of a source reservoir using a reservoir simulator calibrated to field test data because of the wide variance in reservoir composition between wells and high volatility of the fluids produced by EOR projects. Accordingly, in some embodiments, the control system may further include a reservoir simulator operable to simulate the composition of a well or reservoir from which the input stream is sourced. Alternatively, the reservoir simulator may be operable to simulate the composition of the input stream itself. In another alternative, the composition of the input stream may be known or determined by testing and manually or automatically provided to the control system. The control system may then be operable to determine the optimal operating conditions (e.g. temperature and pressure of the stabilization column) for the stabilization system to produce a stabilized crude oil stream having an RVP within a predetermined range based on the composition data received by the control system or determined by the reservoir simulator. In an alternative, the operating conditions of the stabilization system may be determined and adjusted manually. In some aspects, the control system may be operable to simulate the composition of the input stream on a continuous basis and adaptively adjust the operating conditions of the stabilization system in response to changes in the composition of the input stream. In other aspects, the control system may be operable to only simulate the composition of the input stream to determine optimal initial operating conditions of the stabilization system (e.g. optimal initial temperature and initial pressure of the stabilization column).

[0059] In some embodiments, the control system may include one or more models for determining the optimal operating conditions of the stabilization system based on the composition and physical properties and / or conditions of the input stream. In some applications, based on the historian of the control system a startup operating model may be manually selected for the control system to use from a plurality of startup operating models. In some embodiments, the startup operating model may be selected based on where the input stream is sourced from such that the stabilization system may account for compositional variance in the input stream and separate out a stabilized crude oil stream that has an RVP within a predetermined range.

[0060] The one or more models may be or include: regression models (e.g., linear, regularized, partial least squares, and / or nonlinear regression), tree-based models (e.g., decision trees, random forests, gradient-boosted trees), support vector regression and other kernel-based regression methods (e.g., Gaussian process regression), Bayesian regression methods, neural network models (e.g., feed-forward networks, deep neural networks, and / or transformer-based networks), and / or any other suitable model, machine learning algorithm, or methodology. In some implementations, the model may further include an equation-based model (e.g., weighted equations or other parametric functional forms) and / or a hybrid model that combines one or more of the foregoing data-driven models with deterministic process relationships (e.g., mass / energy-balance constraints, thermodynamic property relationships, and / or column performance correlations) to improve predictive accuracy and enforce physically feasible operating conditions.

[0061] In some embodiments, the one or more models of the control system may be trained to determine the optimal pressure and temperature of the stabilization system based on the composition and physical properties and / or conditions of the input stream. The one or more models may be trained on existing composition data and manually assigned operating parameters. Alternatively, the models may be iteratively trained on existing composition data and operating parameters that have been randomly assigned. In further embodiments, the models may be trained using: self-supervised learning, semi-supervised learning, supervised learning, unsupervised learning, reinforcement learning, transfer learning, Bayesian optimization, positive-unlabeled learning, using backpropagation methods, and / or otherwise learned. The model can be learned or trained on: labeled data (e.g., data labeled with the target label), unlabeled data, positive training sets (e.g., a set of data with true positive labels, negative training sets (e.g., a set of data with true negative labels), and / or any other suitable set of data. In some applications, the one or more models may be trained on a continuous basis based on a degree of error between the RVP of the stabilized crude oil stream produced by the stabilization system and the acceptable predetermined range. In other applications, the one or more models may be iteratively trained prior to use within the system.

[0062] As the input stream descends through the random packing of the stabilization column, a gaseous NGL solvent stream of lighter, more volatile hydrocarbons is separated out from the input stream. In some embodiments, the NGL solvent stream may include one or more of ethane (C2), propane (C3), and butane (C4). In other embodiments, the NGL solvent stream may include methane (C1). In yet other embodiments, the NGL solvent stream may include impurities. For example, the impurities present in the NGL stream may include but are not limited to nitrogen (N2), helium (He), carbon dioxide (CO2), hydrogen sulfide (H2S), hydrogen (H2), water, naturally occurring mercury, mercaptans, BTX, salts, process induced impurities such as methanol, or a combination thereof. In some embodiments, the stabilization system may be operable to heat the input stream using a heater of the stabilization system which may vaporize the lighter NGL solvents (C2 / C3 / C4). In some embodiments, C5 is also vaporized by the heater such that the gaseous NGL solvent stream includes C5. In further embodiments, the stabilization system may be operable to heat the input stream using the heater to vaporize the lighter NGL solvents from the input stream to produce an NGL solvent stream heavily weighted toward C2-C4 in composition. In some embodiments, the heater of the stabilization system heats the input stream using a catalytic process, an electrical emersion heater and / or resistive heater, an electrical emersion heater and / or resistive heater utilizing pulse width modulation, internal system heat integration, a direct-fired heating system using the NGL solvent stream as a fuel source, or a direct-fired heating system using a utility gas stream (e.g. methane) extracted from the NGL solvent stream as a fuel source.

[0063] As the NGL solvent stream is separated out from the input stream, the remaining liquid of the input stream continues down the stabilization column to produce a stabilized crude oil stream. The stabilized crude oil stream may be primarily composed of pentane plus (C5+) and may have a reid vapor pressure (RVP) that falls within a predetermined or contracted range. In some embodiments, the stabilized crude oil stream may include hydrocarbons having a molecular weight equal to or greater than the molecular weight of propane. In yet other embodiments, the stabilized crude oil stream may further include impurities. The stabilized crude oil stream may then be collected from the stabilization system and sold as a product.

[0064] Due to variability in reservoir characteristics and input stream composition among different sources of Y-Grade or production streams, and uncertainty in the precise composition of such streams, a stabilized crude oil stream exiting the stabilization column may, in some instances, exhibit a reid vapor pressure (RVP) outside a predetermined or contracted specification range. To address such conditions, the system may further include an off-specification crude recycle loop configured to selectively return at least a portion of the stabilized crude oil stream to the stabilization column for further processing. In some embodiments, the recycle loop includes an RVP measurement device operable to determine whether the RVP of the stabilized crude oil stream falls outside the predetermined range. Where the RVP of the stabilized crude oil stream does fall outside the predetermined range, the control system may be operable to divert the stabilized crude oil stream, or a portion thereof, for recycle back into the stabilization system.

[0065] In some embodiments, the recycle loop may be operable to split the recycled crude oil stream or portion thereof into a first portion and a second portion of the recycled crude oil stream. The recycle loop may be further operable to feed the first portion of the recycled crude oil stream at a location proximate to the heater of the stabilization system. In some applications, the heater of the stabilization system may be operable to heat the first portion of the recycled crude oil stream to a temperature determined by the control system prior to feeding the first portion to the base of the stabilization column such that the stabilization system produces a stabilized crude oil stream with an RVP that falls within the predetermined range. The recycle loop may be further operable to feed the second portion of the recycled crude oil stream to an upper portion of the stabilization column. In some embodiments, the second portion of the recycled crude oil stream may be fed to the top of the stabilization column. In some embodiments, the relative proportions of the first portion and the second portion may be selectively adjusted over a range of about 0% to about 100% based on a measured or desired temperature profile within the stabilization column, such that distribution of the recycled crude oil stream is controlled to maintain thermal stability, vapor-liquid equilibrium, and vapor pressure compliance.

[0066] As mentioned above, in some embodiments, the recycle loop may direct the recycled stabilized crude oil stream or portion thereof to the heater of the stabilization system. In some embodiments, the heater may be operable to heat the recycled stabilized crude oil stream or portion thereof prior to reintroduction into the stabilization column, thereby vaporizing light NGL components including C2, C3, and C4 hydrocarbons from the crude oil stream. Because C5 is also a volatile, and the amount of C5 present within the stabilized crude oil stream affects the RVP, the heater may further be operable to heat the recycled stabilized crude oil stream or portion thereof to vaporize a portion of the C5 present within the stabilized crude oil stream. The vaporized light NGL components may then flow to the top of the stabilization column to form the gaseous NGL solvent stream. The composition of the gaseous NGL solvent stream is heavily weighted to C3 and C4, however, the composition may further include C5 in an amount of about 0 mole % to about 10 mole % of the total gaseous NGL solvent stream. For example, the gaseous NGL solvent stream may include C5 in an amount of about 0 mole % to about 1 mole %, about 0 mole % to about 2 mole %, about 0 mole % to about 3 mole %, about 0 mole % to about 4 mole %, about 0 mole % to about 5 mole %, about 0 mole % to about 6 mole %, about 0 mole % to about 7 mole %, about 0 mole % to about 8 mole %, about 0 mole % to about 9 mole %, about 0 mole % to about 10 mole %, about 1 mole % to about 2 mole %, about 1 mole % to about 3 mole %, about 1 mole % to about 4 mole %, about 1 mole % to about 5 mole %, about 1 mole % to about 6 mole %, about 1 mole % to about 7 mole %, about 1 mole % to about 8 mole %, about 1 mole % to about 9 mole %, about 1 mole % to about 10 mole %, about 2 mole % to about 3 mole %, about 2 mole % to about 4 mole %, about 2 mole % to about 5 mole %, about 2 mole % to about 6 mole %, about 2 mole % to about 7 mole %, about 2 mole % to about 8 mole %, about 2 mole % to about 9 mole %, about 2 mole % to about 10 mole %, about 3 mole % to about 4 mole %, about 3 mole % to about 5 mole %, about 3 mole % to about 6 mole %, about 3 mole % to about 7 mole %, about 3 mole % to about 8 mole %, about 3 mole % to about 9 mole %, about 3 mole % to about 10 mole %, about 4 mole % to about 5 mole %, about 4 mole % to about 6 mole %, about 4 mole % to about 7 mole %, about 4 mole % to about 8 mole %, about 4 mole % to about 9 mole %, about 4 mole % to about 10 mole %, about 5 mole % to about 6 mole %, about 5 mole % to about 7 mole %, about 5 mole % to about 8 mole %, about 5 mole % to about 9 mole %, about 5 mole % to about 10 mole %, about 6 mole % to about 7 mole %, about 6 mole % to about 8 mole %, about 6 mole % to about 9 mole %, about 6 mole % to about 10 mole %, about 7 mole % to about 8 mole %, about 7 mole % to about 9 mole %, about 7 mole % to about 10 mole %, about 8 mole % to about 9 mole %, about 8 mole % to about 10 mole %, or about 9 mole % to about 10 mole % of the total gaseous NGL solvent stream. In some aspects, the heater of the stabilization system may be a heat exchanger. In further embodiments, the heater may be operable to heat the recycled stabilized crude oil stream to a temperature of about 500° F. to about 800° F. For example, the recycle heater may be operable to heat the recycled stabilized crude oil stream or portion thereof to a temperature of about 500° F. to about 525° F., about 500° F. to about 550° F., about 500° F. to about 575° F., about 500° F. to about 600° F., about 500° F. to about 625° F., about 500° F. to about 650° F., about 500° F. to about 675° F., about 500° F. to about 700° F., about 500° F. to about 725° F., about 500° F. to about 750° F., about 500° F. to about 775° F., about 500° F. to about 800° F., about 525° F. to about 550° F., about 525° F. to about 575° F., about 525° F. to about 600° F., about 525° F. to about 625° F., about 525° F. to about 650° F., about 525° F. to about 675° F., about 525° F. to about 700° F., about 525° F. to about 725° F., about 525° F. to about 750° F., about 525° F. to about 775° F., about 525° F. to about 800° F., about 550° F. to about 575° F., about 550° F. to about 600° F., about 550° F. to about 625° F., about 550° F. to about 650° F., about 550° F. to about 675° F., about 550° F. to about 700° F., about 550° F. to about 725° F., about 550° F. to about 750° F., about 550° F. to about 775° F., about 550° F. to about 800° F., about 575° F. to about 600° F., about 575° F. to about 625° F., about 575° F. to about 650° F., about 575° F. to about 675° F., about 575° F. to about 700° F., about 575° F. to about 725° F., about 575° F. to about 750° F., about 575° F. to about 775° F., about 575° F. to about 800° F., about 600° F. to about 625° F., about 600° F. to about 650° F., about 600° F. to about 675° F., about 600° F. to about 700° F., about 600° F. to about 725° F., about 600° F. to about 750° F., about 600° F. to about 775° F., about 600° F. to about 800° F., about 625° F. to about 650° F., about 625° F. to about 675° F., about 625° F. to about 700° F., about 625° F. to about 725° F., about 625° F. to about 750° F., about 625° F. to about 775° F., about 625° F. to about 800° F., about 650° F. to about 675° F., about 650° F. to about 700° F., about 650° F. to about 725° F., about 650° F. to about 750° F., about 650° F. to about 775° F., about 650° F. to about 800° F., about 675° F. to about 700° F., about 675° F. to about 725° F., about 675° F. to about 750° F., about 675° F. to about 775° F., about 675° F. to about 800° F., about 700° F. to about 725° F., about 700° F. to about 750° F., about 700° F. to about 775° F., about 700° F. to about 800° F., about 725° F. to about 750° F., about 725° F. to about 775° F., about 725° F. to about 800° F., about 750° F. to about 775° F., about 750° F. to about 800° F., or about 775° F. to about 800° F. In an alternative embodiment, the heater may be operable to heat the recycled stabilized crude oil stream to a temperature of about 100° F. to about 800° F. In some aspects, the heater may heat the recycled stabilized crude oil stream using a catalytic process, an electrical emersion heater and / or resistive heater, an electrical emersion heater and / or resistive heater utilizing pulse width modulation, internal system heat integration, a direct-fired heating system using the NGL solvent stream as a fuel source, or a direct-fired heating system using a utility gas stream (e.g. methane) extracted from the NGL solvent stream as a fuel source.

[0067] In further embodiments, the control system may be in communication with the recycle loop, and further operable to adjust the operating conditions of the stabilization system to a set of updated operating conditions when the measured RVP of the stabilized crude oil stream falls outside of the predetermined range. For example, the control system may be operable to adjust the temperature and pressure of the stabilization column to a second temperature and a second pressure when the measured RVP of the stabilized crude oil stream falls outside of the predetermined range. The updated operating conditions of the stabilization system may be determined by the control system based on the composition of the input stream and / or RVP of the recycled stabilized crude oil stream as the optimal operating conditions to achieve an RVP of the stabilized crude oil stream within the predetermined range. In some applications, the control system may determine the updated operating conditions of the stabilization system using the one or more models. In some applications, the one or more models may monitor the RVP of the stabilized crude oil stream and determine the updated operating conditions for the stabilization system on a continuous basis. In other applications, the one or more models may measure the RVP of the stabilized crude oil stream and determine the updated operating conditions of the stabilization system on a periodic basis. In some aspects, the RVP of the stabilized crude oil stream may be measured continuously or once per every about 30 seconds to about 6 hours. For example, RVP of the stabilized crude oil stream may be measured once per every about 30 seconds to about 1 minute, about 30 seconds to about 5 minutes, about 30 seconds to about 20 minutes, about 30 seconds to about 40 minutes, about 30 seconds to about 1 hour, about 30 seconds to about 2 hours, about 30 seconds to about 3 hours, about 30 seconds to about 4 hours, about 30 seconds to about 5 hours, about 30 seconds to about 6 hours, about 1 minute to about 5 minutes, about 1 minute to about 20 minutes, about 1 minute to about 40 minutes, about 1 minute to about 1 hour, about 1 minute to about 2 hours, about 1 minute to about 3 hours, about 1 minute to about 4 hours, about 1 minute to about 5 hours, about 1 minute to about 6 hours, about 5 minutes to about 20 minutes, about 5 minutes to about 40 minutes, about 5 minutes to about 1 hour, about 5 minutes to about 2 hours, about 5 minutes to about 3 hours, about 5 minutes to about 4 hours, about 5 minutes to about 5 hours, about 5 minutes to about 6 hours, about 20 minutes to about 40 minutes, about 20 minutes to about 1 hour, about 20 minutes to about 2 hours, about 20 minutes to about 3 hours, about 20 minutes to about 4 hours, about 20 minutes to about 5 hours, about 20 minutes to about 6 hours, about 40 minutes to about 1 hour, about 40 minutes to about 2 hours, about 40 minutes to about 3 hours, about 40 minutes to about 4 hours, about 40 minutes to about 5 hours, about 40 minutes to about 6 hours, about 1 hour to about 2 hours, about 1 hour to about 3 hours, about 1 hour to about 4 hours, about 1 hour to about 5 hours, about 1 hour to about 6 hours, about 2 hours to about 3 hours, about 2 hours to about 4 hours, about 2 hours to about 5 hours, about 2 hours to about 6 hours, about 3 hours to about 4 hours, about 3 hours to about 5 hours, about 3 hours to about 6 hours, about 4 hours to about 5 hours, about 4 hours to about 6 hours, or about 5 hours to about 6 hours. In some variants of the present system, the operating conditions of the stabilization system may be adjusted to the updated operating conditions manually. Once the stabilized crude oil stream is determined to have an RVP that falls within the predetermined range, the stabilized crude oil stream may be cooled and fed into a storage tank or transportation container / vehicle for sale as a commodity product.

[0068] In some embodiments, the stabilization process is performed at elevated pressure and temperature operating conditions, including temperatures of up to about 800° F. and pressures of up to about 600 psig, such that a crude oil stream is stabilized to a target RVP within a predetermined range in a single high-pressure, high-temperature stabilization step. Under these conditions, light hydrocarbon components are sufficiently removed such that, upon subsequent cooling of the stabilized crude oil stream to ambient conditions, the stabilized crude oil remains subcooled relative to its bubble point and does not outgas during transfer to storage. This results in improved stabilization efficiency, increased liquid recovery, and reduced emissions associated with storage tank off-gassing. In some embodiments, the stabilized crude oil stream may be directed directly to a pipeline, bypassing intermediate storage, wherein the pipeline transport functions as a final stabilization stage prior to delivery while maintaining compliance with the specified vapor pressure requirements.

[0069] In some embodiments, the predetermined range of RVP may be about 6 psia to about 12 psia. For example, the predetermined range may be about 6 psia to about 7 psia, about 6 psia to about 8 psia, about 6 psia to about 9 psia, about 6 psia to about 10 psia, about 6 psia to about 11 psia, about 6 psia to about 12 psia, about 7 psia to about 8 psia, about 7 psia to about 9 psia, about 7 psia to about 10 psia, about 7 psia to about 11 psia, about 7 psia to about 12 psia, about 8 psia to about 9 psia, about 8 psia to about 10 psia, about 8 psia to about 11 psia, about 8 psia to about 12 psia, about 9 psia to about 10 psia, about 9 psia to about 11 psia, about 9 psia to about 12 psia, about 10 psia to about 11 psia, about 10 psia to about 12 psia, or about 11 psia to about 12 psia. In one particular example, the stabilization process may be performed at elevated pressure and temperature operating conditions to stabilize the crude oil stream to a target RVP of about 9 psia. In some embodiments, the target RVP or predetermined range of RVP may be determined based on where the stabilized crude oil of the stabilized crude oil stream is marketed as well as other economic factors. For example, the target RVP or predetermined range of RVP may be lowered to drive more volume to the solvent tank where an operator wants to generate a larger volume of NGL solvent. As another example, the target RVP or predetermined range of RVP may be raised to maximize crude oil sales where the operator has available “dry” crude to blend with. In some embodiments, the NGL solvent stream separated from the stabilized crude oil stream may rise to and exit at the top of the stabilization column. Because the NGL solvent stream is gaseous at this point, it may be desirable for the stabilization system to include a condenser system operable to condense the NGL solvent stream such that it may be used as a liquid solvent for injection in EOR operations. In some embodiments, the condenser system may include a compressor. The compressor may be operable to compress the gaseous NGL solvent stream exiting the stabilization column to a pressure suitable for condensing propane and butane in addition to any pentane present in the NGL solvent stream. In some applications the condenser system may further include a cooler operable to condense the compressed gaseous NGL solvent to produce a condensed NGL solvent stream including propane and butane. In further applications, the condensed NGL solvent stream may further include pentane. In yet further embodiments, the condenser system may include only a cooler operable to condense the gaseous NGL solvent to produce the condensed NGL solvent stream. The cooler of the condenser system may, in some embodiments, be an air cooler, a water cooler, a heat exchanger suitable for recycling the heat of the gaseous NGL solvent stream, or any other suitable heat exchanger or cooler. In other embodiments, the condenser system may include an inlet pump and an overhead condenser in fluid communication with the stabilization column. The overhead condenser may be operable to condense the gaseous NGL solvent stream using mechanical refrigeration, membranes, or ambient air cooling to produce the liquid NGL solvent stream. The remaining gaseous portion of the gaseous NGL solvent stream may include methane, ethane, any light impurities separated from the stabilized crude oil stream by the stabilization column, or a combination thereof. In further applications, the stabilization system may be operable to condense the gaseous NGL solvent stream to produce a liquid NGL solvent stream including ethane, propane, and butane. In yet further applications, the stabilization system may be operable to condense the gaseous NGL solvent stream to produce a liquid NGL solvent stream including ethane, propane, butane, and pentane. In this case, the remaining gaseous portion may include methane, any light impurities separated from the stabilized crude oil stream by the stabilization system, or a combination thereof. In some aspects, the remaining gaseous components may be separated from the condensed NGL solvent stream and sold as a utility gas or used internally within the system as a utility gas.

[0070] The present system may further include a solvent storage tank operable to store the condensed NGL solvent stream for sale as an injectable solvent for EOR. In some embodiments, the solvent stream downstream of the cooler system to and including the storage tank may be in fluid communication with the stabilization system via a reflux loop operable to recycle a portion of the NGL solvent stream within the solvent storage tank to compensate for deviations in mass flowrate operating variables beyond a predetermined range. In some embodiments, the control system may monitor the mass flow rate of the stabilization system to determine whether the mass flowrate operating variables of the stabilization system do not fall within the predetermined range. In further embodiments, the control system may determine the amount of NGL solvent to recycle to the stabilization system based on the mass flowrate operating variables of the stabilization system, the operating conditions of the stabilization system, the RVP of the stabilized crude oil stream, the composition of the input stream, or a combination thereof. In some embodiments, the reflux loop recycles the portion of the NGL solvent stream such that it is reinjected into the top of the stabilization column. In one particular example, the reflux loop may be operable to monitor the build up of impurities within the stabilization column and heater and inject a portion of the NGL solvent stream into the stabilization column to flush out the build up of asphaltene and / or paraffin within the stabilization column and heater.

[0071] As a result of the adaptability of the stabilization system via the control system of the present system in handling the stabilization of Y-Grade of variable compositions, the present system is suitable for stabilizing Y-Grade from various sources. For example, the Y-Grade or unfractionated NGLs of the input stream may be trucked in, sourced from a pipeline, sourced from a storage tank, directly obtained from an onsite 3 phase production separator, or directly obtained from the output of a gas conditioning plant Where the presently disclosed systems are installed onsite at a gas conditioning plant, the input stream may include the unfractionated NGL or Y-Grade produced by the gas conditioning plant and may further include unfractionated NGL or Y-Grade obtained from one or more additional sources. In some embodiments, the ancillary equipment of the present systems working in combination with the stabilization system may be dictated by a combination of the operating conditions of the stabilization system and the source from which the input stream is obtained.

[0072] In one particular example, as depicted in FIG. 1, the presently disclosed system for stabilizing and separating Y-Grade natural gas liquids (NGLs) may be installed onsite at an operator's lease where the Y-Grade is trucked in. In such a case, the composition of the input stream may be similar to the exemplary Y-Grade composition presented in Table 1. Referring to FIG. 1, the system may further include a Y-Grade storage tank (001) to supply the input stream to the stabilization system. In some embodiments, the Y-Grade may be stored within the Y-Grade storage tank at a temperature of about 32° F. to about 130° F. For example, the Y-Grade may be stored within the Y-Grade storage tank at a temperature of about 32° F. to about 40° F., about 32° F. to about 50° F., about 32° F. to about 60° F., about 32° F. to about 70° F., about 32° F. to about 80° F., about 32° F. to about 90° F., about 32° F. to about 100° F., about 32° F. to about 110° F., about 32° F. to about 120° F., about 32° F. to about 130° F., about 40° F. to about 50° F., about 40° F. to about 60° F., about 40° F. to about 70° F., about 40° F. to about 80° F., about 40° F. to about 90° F., about 40° F. to about 100° F., about 40° F. to about 110° F., about 40° F. to about 120° F., about 40° F. to about 130° F., about 50° F. to about 60° F., about 50° F. to about 70° F., about 50° F. to about 80° F., about 50° F. to about 90° F., about 50° F. to about 100° F., about 50° F. to about 110° F., about 50° F. to about 120° F., about 50° F. to about 130° F., about 60° F. to about 70° F., about 60° F. to about 80° F., about 60° F. to about 90° F., about 60° F. to about 100° F., about 60° F. to about 110° F., about 60° F. to about 120° F., about 60° F. to about 130° F., about 70° F. to about 80° F., about 70° F. to about 90° F., about 70° F. to about 100° F., about 70° F. to about 110° F., about 70° F. to about 120° F., about 70° F. to about 130° F., about 80° F. to about 90° F., about 80° F. to about 100° F., about 80° F. to about 110° F., about 80° F. to about 120° F., about 80° F. to about 130° F., about 90° F. to about 100° F., about 90° F. to about 110° F., about 90° F. to about 120° F., about 90° F. to about 130° F., about 100° F. to about 110° F., about 100° F. to about 120° F., about 100° F. to about 130° F., about 110° F. to about 120° F., about 110° F. to about 130° F., about 120° F. to about 130° F., or about 130° F. to about 130° F. In further embodiments, the Y-Grade may be stored within the Y-Grade storage tank at a pressure of about 50 psig to about 250 psig. For example, the Y-Grade may be stored within the Y-Grade storage tank at a pressure of about 50 psig to about 75 psig, about 50 psig to about 100 psig, about 50 psig to about 125 psig, about 50 psig to about 150 psig, about 50 psig to about 175 psig, about 50 psig to about 200 psig, about 50 psig to about 225 psig, about 50 psig to about 250 psig, about 75 psig to about 100 psig, about 75 psig to about 125 psig, about 75 psig to about 150 psig, about 75 psig to about 175 psig, about 75 psig to about 200 psig, about 75 psig to about 225 psig, about 75 psig to about 250 psig, about 100 psig to about 125 psig, about 100 psig to about 150 psig, about 100 psig to about 175 psig, about 100 psig to about 200 psig, about 100 psig to about 225 psig, about 100 psig to about 250 psig, about 125 psig to about 150 psig, about 125 psig to about 175 psig, about 125 psig to about 200 psig, about 125 psig to about 225 psig, about 125 psig to about 250 psig, about 150 psig to about 175 psig, about 150 psig to about 200 psig, about 150 psig to about 225 psig, about 150 psig to about 250 psig, about 175 psig to about 200 psig, about 175 psig to about 225 psig, about 175 psig to about 250 psig, about 200 psig to about 225 psig, about 200 psig to about 250 psig, or about 225 psig to about 250 psig. Depending on the pressure in the Y-Grade storage tank the present system may further include a transfer pump (002) operable to deliver the unfractionated NGL of the input stream to the stabilization system (003). Where the pressure within the Y-Grade storage tank is high enough, the input stream may feed to the stabilization system. Where the pressure within the Y-Grade storage tank is lower, the input stream may be pumped to the stabilization system using the transfer pump (002).

[0073] Upon being fed to the stabilization system (003), the input stream may be separated into two streams: the heavier pentane plus stabilized crude oil stream and the lighter ethane to pentane (C2 to C5) components that make up the NGL solvent stream. According to some aspects, the liquid pentane plus (C5+) components, in addition to any remaining C3 and C4 present in the stabilized crude oil stream may flow from the stabilization column to an oil storage tank (004) or directly to an oil sales pipeline. In some embodiments, the lighter NGL solvent stream of ethane, propane, butanes, and pentanes (C2, C3, C4, and C5) may exit the stabilization system in a liquid state. The liquid NGL solvent stream may be delivered to the Solvent Storage Tank (005) for storage.

[0074] According to further aspects, the NGL solvent stream may exit the stabilization column in a gaseous state. In some embodiments, the gaseous NGL solvent stream may include gaseous ethane, propane, butane, and pentane (C2, C3, C4, and C5). The condensing system of the stabilization system may be operable to condense and separate the propane, butane, and pentane from the remaining gaseous components of the NGL solvent stream. In some aspects, the remaining gaseous components of the NGL solvent stream may include gaseous ethane and propane. In order to condense the remaining propane within the gaseous components of the NGL solvent stream, the system may further include a cooling system (006) in fluid communication with the top of the stabilization system. The gaseous portion of the NGL solvent stream may flow into the suction of a small compressor, part of the cooling system, for compression to a pressure amenable for condensing the gaseous portion. The cooling system may further include an air cooler operable to cool and condense the compressed gas portion such that predominantly propane (C3), may condense from the gaseous portion and flow to the Solvent Storage Tank (005). The liquid NGL solvent that is stored within the solvent stream may then be sold or used as a well injectant for onsite EOR operations. The liquid NGL solvent may be used by the reflux loop of the system to account for deviations in the mass flowrate operating variables of the system.

[0075] In some applications, uncondensed gas, predominantly methane, may be liberated from the input stream by the present system. For example, the utility gas (007) may be separated from the gaseous NGL stream in the stabilization system (003) and / or in the cooling system (006). In some embodiments, it may be desirable for the system to be operable to utilize the liberated utility gas as a utility gas for the on-site equipment. By using the utility gas liberated by both systems (003 and 006) as a utility gas on site, the present systems may reduce the carbon emissions from a gas conditioning plant because of the cleaner burn of methane compared to that of the rich gas mixture, including condensates that is conventionally used within the industry for onsite fuel utilization. Additional carbon emission reduction may also be attributed to reduced tanker truck transportation related to both volumes and mileage.

[0076] In another embodiment, as depicted in FIG. 2A, the Y-Grade input stream of the present system may be supplied by a Y-Grade pipeline (008). Typical operating pressures for Y-Grade pipelines fall around about 400 psi to about 600 psi with a combined concentration of methane and ethane being greater than about 30 mole %. In such a case, it may be beneficial for the system to include an orifice (009), or another device designed to achieve a pressure drop of the input stream upstream from the stabilization system. In some embodiments, the pressure of the input stream delivered by pipeline may require a reduction in pressure to effectively liberate a high concentration of ethane gas from the input stream. Where the pressure drop liberates a high concentration of ethane gas from the input stream, the system may further include a gas / fluid separator (010) installed upstream of the stabilization system (011). In some embodiments, the gas / fluid separator may be operable to separate the gaseous ethane (C2) from the input stream such that it may be sold as a product stream. Alternatively, the rich ethane gas coming off the gas separator may be returned to the Y-Grade pipeline. Because the gas / fluid separator removes a large portion of the methane and ethane content of the input stream, the composition of the input stream fed to the stabilization system (011) may be highly rich in propane and butane (C3 and C4) with the majority of the liquids in the stream being delivered to the Solvent Storage Tank (014) following processing in the stabilization system. According to such embodiments as depicted in FIG. 2B, the resulting pentane plus (C5+) stabilized crude oil stream flowing to the oil storage tank (012) may represent less than one third of the total liquids fed to the stabilization system in the input stream.

[0077] Variations of this embodiment, as depicted in FIG. 2B, may operate at a pressure similar to the pressure of the Y-Grade pipeline supply. This permits the ethane (C2) to remain in a liquid state, consequently increasing the solvent supply volume. In the scenario depicted by FIG. 2B, the system may include a capacitor (016) for the Y-Grade input stream upstream of the stabilization system (017) as necessary. In some embodiments, the capacitor may be operable to buffer the flow of the input stream to the stabilization system to provide a more stable flow, pressure, and composition for processing. According to some aspects of the present system, the stabilization system may deliver liquid ethane, propane, butane, and pentane to the solvent storage tank (020). Any off-gas from the stabilization system may be compressed and condensed to a liquid (019) for storage at the solvent storage tank (020).

[0078] Referring to FIG. 3, in further embodiments, the presently disclosed system may be installed on a neutral site and receive a Y-Grade supply from tanker trucks from multiple locations (022). This may require a larger capacity system which may in turn provide an even greater carbon emission reduction attributed to further reduction in tanker truck mileage. In such a case the system may include a Y-Grade receiving station which includes storage tank(s) (023) for the input stream.

[0079] In yet another embodiment, the system may be installed on the site of an oil and gas producer who owns and operates their own gas conditioning plant(s) which generates Y-Grade. In the current market, this Y-Grade is typically sold to midstream refiners for 30% to 40% of WTI Oil Pricing. Producers may therefore benefit from the implementation of the present systems by further extracting additional pentane plus (C5+) from the Y-Grade to augment their oil sales stream and by supplying their own solvent for well stimulation treatments and EOR projects. This represents a significant cost savings and extremely robust economics for these applications. In some embodiments, producers may control the operation of the stabilization system to obtain an optimum split of butane (C4) and pentane (C5) going to the NGL solvent and stabilized crude oil streams respectively. In further embodiments, the propane, butane, and pentane (C3-C5) produced by the present system may be reinjected into a well or reservoir for EOR operations. Not only may the reinjection of propane, butane, and pentane (C3-C5) for EOR result in an improved extraction of crude oil and dry gas from the well, the reinjection may result in the sequestration of the C3-C5 in the reservoir, thus significantly reducing an operator's carbon intensity.

[0080] In further embodiments of the present system, the NGL solvent streams produced by the present system may be used in EOR projects. In some embodiments, the NGL solvent stream may be used alone or in combination with Y-Grade in EOR projects by injecting the NGL solvent stream and / or Y-Grade into the well or reservoir where the system is installed. Referring to FIG. 4, in some embodiments, the present system may be incorporated into an NGL recycling system operable to separate NGL solvent stream products (C2-C5) from well production (024) and reinject the NGL solvent stream products back into the well for EOR (027). When the NGL solvent stream is injected downhole in a well, the returned produced fluids from the well(s) (024) may require initial processing prior to being fed to the stabilization system. Accordingly, the well production system may include a low pressure three phase separator (025) operable to separate the produced well fluid into three streams: wet gas, volatile oil, and water. Where the well production system is used in combination with the recycling of the NGL solvent stream produced by the stabilization system, the NGL solvent stream may be used as a liquid solvent injectant stream comprised predominantly of propane and butane (C3 and C4). In some embodiments, the liquid NGL solvent stream may be used for EOR injection using a high recovery ratio from about 50% to about 100%. For example, the NGL solvent stream may be used for EOR injection using a high recovery ration from about 50% to about 55%, about 50% to about 60%, about 50% to about 65%, about 50% to about 70%, about 50% to about 75%, about 50% to about 80%, about 50% to about 85%, about 50% to about 90%, about 50% to about 95%, about 50% to about 100%, about 55% to about 60%, about 55% to about 65%, about 55% to about 70%, about 55% to about 75%, about 55% to about 80%, about 55% to about 85%, about 55% to about 90%, about 55% to about 95%, about 55% to about 100%, about 60% to about 65%, about 60% to about 70%, about 60% to about 75%, about 60% to about 80%, about 60% to about 85%, about 60% to about 90%, about 60% to about 95%, about 60% to about 100%, about 65% to about 70%, about 65% to about 75%, about 65% to about 80%, about 65% to about 85%, about 65% to about 90%, about 65% to about 95%, about 65% to about 100%, about 70% to about 75%, about 70% to about 80%, about 70% to about 85%, about 70% to about 90%, about 70% to about 95%, about 70% to about 100%, about 75% to about 80%, about 75% to about 85%, about 75% to about 90%, about 75% to about 95%, about 75% to about 100%, about 80% to about 85%, about 80% to about 90%, about 80% to about 95%, about 80% to about 100%, about 85% to about 90%, about 85% to about 95%, about 85% to about 100%, about 90% to about 95%, about 90% to about 100%, or about 95% to about 100%. The recovery ratio may quantify how much of the produced NGL stream is recovered and re-injected back into the well or reservoir.

[0081] In some applications, the wet gas composition obtained from the low pressure three phase separator may predominantly include methane, ethane and propane (C1, C2, and C3). In further applications, the wet gas composition may further include butane (C4). In some applications, the off gas from the production separator may be used to fuel a compression / cooling / condensing system (026) operable to condense the C2, C3, and C4 out of the wet gas stream using multiple stages of compression, cooling and condensation to form the NGL solvent stream. This liquid NGL solvent stream is fed to the solvent storage tank for reinjection (027). In further applications, the volatile oil stream produced by the three-phase separator may include liquid C3 and C4 mixed in with pentane plus (C5+). In some embodiments, the volatile oil stream may be joined with the Y-Grade input stream prior to being fed into the stabilization system. In other embodiments, the volatile oil stream may be fed to the stabilization system independently of the Y-Grade input stream. In yet other alternate embodiments, the volatile oil stream may be the only input stream of the system. The Y-Grade input stream and volatile oil stream may be processed by the stabilization system to produce a stabilized crude oil stream and a NGL solvent stream to be further processed as discussed above. In some applications, the stabilized crude oil may be sold or used by the operator or a midstream company for blending purposes with other crude supplies. Because of the importance of maintaining the operating conditions of the stabilization system, in some embodiments, the volatile oil stream may be fed to the stabilization column using a transfer pump separate from the transfer pump used for the input stream. In other embodiments, the volatile oil stream may be fed to a volatile oil storage tank for storage prior to being fed to the top of the stabilization column.

[0082] In some aspects, the present system may be a mobile system for stabilizing and separating Y-Grade NGL. Where the present system is a mobile system for stabilizing and separating Y-Grade NGL a cellular service and / or satellite service may be utilized to remotely operate the mobile system. In other aspects, the present system may be stationary. For example, the system may be installed at an oil and gas production facility, a gas conditioning plant, a Y-Grade aggregation terminal, or a distribution facility.4. Methods

[0083] The present disclosure further provides for methods of processing unfractionated natural gas liquids (NGLs) including feeding an input stream including unfractionated NGLs or Y-Grade to a stabilization system, separating hydrocarbons having a molecular weight less than or equal to butane from the input stream to produce a gaseous NGL solvent stream and a crude oil stream, and stabilizing the crude oil stream to produce a stabilized crude oil stream using the stabilization system.

[0084] In some embodiments, the input stream may have a composition similar to the exemplary Y-Grade composition of Table 1 or Table 2. However, the input stream may be a Y-Grade stream including NGLs of any composition and is not restricted to the compositions of Tables 1 and 2. The input stream may include methane, ethane, propane, butane, and pentane plus, as well as any other impurities often found in Y-Grade and NGL extracted from production wells.

[0085] In some applications, the input stream may be fed to the stabilization system at a temperature of about 32° F. to about 130° F. For example, the input stream may be fed to the stabilization system at a temperature of about 32° F. to about 40° F., about 32° F. to about 50° F., about 32° F. to about 60° F., about 32° F. to about 70° F., about 32° F. to about 80° F., about 32° F. to about 90° F., about 32° F. to about 100° F., about 32° F. to about 110° F., about 32° F. to about 120° F., about 32° F. to about 130° F., about 40° F. to about 50° F., about 40° F. to about 60° F., about 40° F. to about 70° F., about 40° F. to about 80° F., about 40° F. to about 90° F., about 40° F. to about 100° F., about 40° F. to about 110° F., about 40° F. to about 120° F., about 40° F. to about 130° F., about 50° F. to about 60° F., about 50° F. to about 70° F., about 50° F. to about 80° F., about 50° F. to about 90° F., about 50° F. to about 100° F., about 50° F. to about 110° F., about 50° F. to about 120° F., about 50° F. to about 130° F., about 60° F. to about 70° F., about 60° F. to about 80° F., about 60° F. to about 90° F., about 60° F. to about 100° F., about 60° F. to about 110° F., about 60° F. to about 120° F., about 60° F. to about 130° F., about 70° F. to about 80° F., about 70° F. to about 90° F., about 70° F. to about 100° F., about 70° F. to about 110° F., about 70° F. to about 120° F., about 70° F. to about 130° F., about 80° F. to about 90° F., about 80° F. to about 100° F., about 80° F. to about 110° F., about 80° F. to about 120° F., about 80° F. to about 130° F., about 90° F. to about 100° F., about 90° F. to about 110° F., about 90° F. to about 120° F., about 90° F. to about 130° F., about 100° F. to about 110° F., about 100° F. to about 120° F., about 100° F. to about 130° F., about 110° F. to about 120° F., about 110° F. to about 130° F., about 120° F. to about 130° F., or about 130° F. to about 130° F. In other applications, the input stream may be fed to the stabilization system at a pressure of about 100 psi to about 600 psi prior to being fed to the top of the stabilization column. For example, the input stream may be fed to the stabilization column at a pressure of about 100 psi to about 150 psi, about 100 psi to about 200 psi, about 100 psi to about 250 psi, about 100 psi to about 300 psi, about 100 psi to about 350 psi, about 100 psi to about 400 psi, about 100 psi to about 450 psi, about 100 psi to about 500 psi, about 100 psi to about 550 psi, about 100 psi to about 600 psi, about 150 psi to about 200 psi, about 150 psi to about 250 psi, about 150 psi to about 300 psi, about 150 psi to about 350 psi, about 150 psi to about 400 psi, about 150 psi to about 450 psi, about 150 psi to about 500 psi, about 150 psi to about 550 psi, about 150 psi to about 600 psi, about 200 psi to about 250 psi, about 200 psi to about 300 psi, about 200 psi to about 350 psi, about 200 psi to about 400 psi, about 200 psi to about 450 psi, about 200 psi to about 500 psi, about 200 psi to about 550 psi, about 200 psi to about 600 psi, about 250 psi to about 300 psi, about 250 psi to about 350 psi, about 250 psi to about 400 psi, about 250 psi to about 450 psi, about 250 psi to about 500 psi, about 250 psi to about 550 psi, about 250 psi to about 600 psi, about 300 psi to about 350 psi, about 300 psi to about 400 psi, about 300 psi to about 450 psi, about 300 psi to about 500 psi, about 300 psi to about 550 psi, about 300 psi to about 600 psi, about 350 psi to about 400 psi, about 350 psi to about 450 psi, about 350 psi to about 500 psi, about 350 psi to about 550 psi, about 350 psi to about 600 psi, about 400 psi to about 450 psi, about 400 psi to about 500 psi, about 400 psi to about 550 psi, about 400 psi to about 600 psi, about 450 psi to about 500 psi, about 450 psi to about 550 psi, about 450 psi to about 600 psi, about 500 psi to about 550 psi, about 500 psi to about 600 psi, or about 550 psi to about 600 psi.

[0086] In some applications, the input stream may be fed to the top of the stabilization column for processing. As the input stream descends through the stabilization column, the stabilization column may function to separate the input stream into two primary streams, an NGL solvent stream and a stabilized crude oil stream. In some embodiments, the stabilization column may include a bed of randomly packed packing elements arranged to define a plurality of tortuo us vapor and liquid flow paths distributed throughout the cross-section of the column. The packing elements may include metallic packing bodies having characteristic sizes of about 1 inch to about 3 inches. For example, the metallic packing bodies may have characteristic sizes of about 1.00 inch to about 1.25 inches, about 1.00 inch to about 1.50 inches, about 1.00 inch to about 1.75 inches, about 1.00 inch to about 2.00 inches, about 1.00 inch to about 2.25 inches, about 1.00 inch to about 2.50 inches, about 1.00 inch to about 2.75 inches, about 1.00 inch to about 3.00 inches, about 1.25 inches to about 1.50 inches, about 1.25 inches to about 1.75 inches, about 1.25 inches to about 2.00 inches, about 1.25 inches to about 2.25 inches, about 1.25 inches to about 2.50 inches, about 1.25 inches to about 2.75 inches, about 1.25 inches to about 3.00 inches, about 1.50 inches to about 1.75 inches, about 1.50 inches to about 2.00 inches, about 1.50 inches to about 2.25 inches, about 1.50 inches to about 2.50 inches, about 1.50 inches to about 2.75 inches, about 1.50 inches to about 3.00 inches, about 1.75 inches to about 2.00 inches, about 1.75 inches to about 2.25 inches, about 1.75 inches to about 2.50 inches, about 1.75 inches to about 2.75 inches, about 1.75 inches to about 3.00 inches, about 2.00 inches to about 2.25 inches, about 2.00 inches to about 2.50 inches, about 2.00 inches to about 2.75 inches, about 2.00 inches to about 3.00 inches, about 2.25 inches to about 2.50 inches, about 2.25 inches to about 2.75 inches, about 2.25 inches to about 3.00 inches, about 2.50 inches to about 2.75 inches, about 2.50 inches to about 3.00 inches, or about 2.75 inches to about 3.00 inches. In further embodiments, the packing elements may collectively define a void fraction of about 85% to about 95%. For example, the packing elements may collectively define a void fraction of about 85% to about 86%, about 85% to about 87%, about 85% to about 88%, about 85% to about 89%, about 85% to about 90%, about 85% to about 91%, about 85% to about 92%, about 85% to about 93%, about 85% to about 94%, about 85% to about 95%, about 86% to about 87%, about 86% to about 88%, about 86% to about 89%, about 86% to about 90%, about 86% to about 91%, about 86% to about 92%, about 86% to about 93%, about 86% to about 94%, about 86% to about 95%, about 87% to about 88%, about 87% to about 89%, about 87% to about 90%, about 87% to about 91%, about 87% to about 92%, about 87% to about 93%, about 87% to about 94%, about 87% to about 95%, about 88% to about 89%, about 88% to about 90%, about 88% to about 91%, about 88% to about 92%, about 88% to about 93%, about 88% to about 94%, about 88% to about 95%, about 89% to about 90%, about 89% to about 91%, about 89% to about 92%, about 89% to about 93%, about 89% to about 94%, about 89% to about 95%, about 90% to about 91%, about 90% to about 92%, about 90% to about 93%, about 90% to about 94%, about 90% to about 95%, about 91% to about 92%, about 91% to about 93%, about 91% to about 94%, about 91% to about 95%, about 92% to about 93%, about 92% to about 94%, about 92% to about 95%, about 93% to about 94%, about 93% to about 95%, or about 94% to about 95%.

[0087] In some applications, the bed of randomly packed packing elements provides a distributed surface area for vapor-liquid contact while simultaneously allowing upward vapor flow through interstitial spaces formed between adjacent packing elements. The randomized geometry disrupts preferential flow paths, reduces vapor channeling, and promotes repeated redistribution of liquid across the bed of randomly backed packing elements, thereby enhancing separation of light hydrocarbon components from the descending liquid of the input stream.

[0088] In further applications, the use of random packing may improve phase disengagement and mass-transfer efficiency, resulting in a stabilized hydrocarbon stream having a reduced vapor pressure and improved compositional stability relative to stabilization columns lacking internal packing. In some embodiments, the randomly packed packing material may be a stainless steel alloy, carbon steel alloy, aluminum alloy, plastic, a ceramic, or a combination thereof.

[0089] In some alternative embodiments, the stabilization column may include a bed of structured packing elements. In some aspects, the structured packing elements may include a plurality of corrugated metallic sheets. The corrugated metallic sheets may be arranged in an ordered geometry to define a network of inclined, intersecting flow passages. In one embodiment, the corrugated metallic sheets may be stacked to form the structured packing elements that collectively define the packed height of the column. In some embodiments, the stacked corrugated metallic sheets form a plurality of discrete structured packing elements positioned adjacent to one another within the stabilization column. In some embodiments, the corrugated metallic sheets of adjacent packing elements may be oriented at different angular alignments to promote redistribution of vapor and liquid. Liquid from the input stream introduced at the top of the stabilization column flows downward by gravity along the inclined surfaces of the corrugated metallic sheets, while vapor is permitted to flow upward counter-currently through the open flow passages formed between corrugations of the stacked corrugated metallic sheets, thereby increasing interfacial contact and mass transfer efficiency. In some applications, the flow passages formed between the corrugations may be non-cylindrical and non-rectangular. In further applications, the flow passages formed between the corrugations may be distributed throughout a cross-section of the packing, and do not extend continuously from the top of the stabilization column to the bottom of the stabilization column, such that maldistribution and channeling are reduced. In some embodiments, surface features such as perforations, texturing, wire-mesh constructions, or a combination thereof may be employed on the surface of the stacked corrugated metallic sheets to enhance wettability and vapor-liquid interaction. In further embodiments, multiple packing elements may be vertically stacked to provide a desired separation performance within the stabilization column.

[0090] In some embodiments, the stabilization column may include a bed of structured packing elements that define one or more vertical flow channels distinct from inclined flow passages formed by the packing geometry. The vertical flow channels provide low-resistance pathways for upward vapor flow while surrounding structured packing promotes distributed liquid flow and vapor-liquid contact. By diverting a portion of vapor flow away from primary mass-transfer surfaces, localized vapor loading and liquid entrainment may be reduced, thereby improving phase disengagement and enhancing removal of light hydrocarbon components from a descending liquid stream to produce a stabilized hydrocarbon stream having reduced vapor pressure and improved compositional stability relative to stabilization columns employing structured packing alone. In some embodiments, the bed of structured packing elements may include about 2 to about 8 vertical flow channels. For example, the bed of structured packing elements may include about 2 to about 3, about 2 to about 4, about 2 to about 5, about 2 to about 6, about 2 to about 7, about 2 to about 8, about 3 to about 4, about 3 to about 5, about 3 to about 6, about 3 to about 7, about 3 to about 8, about 4 to about 5, about 4 to about 6, about 4 to about 7, about 4 to about 8, about 5 to about 6, about 5 to about 7, about 5 to about 8, about 6 to about 7, about 6 to about 8, or about 7 to about 8 vertical flow channels. In some aspects, the vertical flow channels may have a hydraulic diameter of about 2 inches to about 4 inches. For example, the vertical flow channels may have a hydraulic diameter of about 2.00 inches to about 2.25 inches, about 2.00 inches to about 2.50 inches, about 2.00 inches to about 2.75 inches, about 2.00 inches to about 3.00 inches, about 2.00 inches to about 3.25 inches, about 2.00 inches to about 3.50 inches, about 2.00 inches to about 3.75 inches, about 2.00 inches to about 4.00 inches, about 2.25 inches to about 2.50 inches, about 2.25 inches to about 2.75 inches, about 2.25 inches to about 3.00 inches, about 2.25 inches to about 3.25 inches, about 2.25 inches to about 3.50 inches, about 2.25 inches to about 3.75 inches, about 2.25 inches to about 4.00 inches, about 2.50 inches to about 2.75 inches, about 2.50 inches to about 3.00 inches, about 2.50 inches to about 3.25 inches, about 2.50 inches to about 3.50 inches, about 2.50 inches to about 3.75 inches, about 2.50 inches to about 4.00 inches, about 2.75 inches to about 3.00 inches, about 2.75 inches to about 3.25 inches, about 2.75 inches to about 3.50 inches, about 2.75 inches to about 3.75 inches, about 2.75 inches to about 4.00 inches, about 3.00 inches to about 3.25 inches, about 3.00 inches to about 3.50 inches, about 3.00 inches to about 3.75 inches, about 3.00 inches to about 4.00 inches, about 3.25 inches to about 3.50 inches, about 3.25 inches to about 3.75 inches, about 3.25 inches to about 4.00 inches, about 3.50 inches to about 3.75 inches, about 3.50 inches to about 4.00 inches, or about 3.75 inches to about 4.00 inches. In further aspects, the vertical flow channels may collectively define an open flow area of about 3% to about 15% of the cross-sectional area of the stabilization column. For example, the vertical flow channels may collectively define an open flow area of about 3% to about 6%, about 3% to about 9%, about 3% to about 12%, about 3% to about 15%, about 6% to about 9%, about 6% to about 12%, about 6% to about 15%, about 9% to about 12%, about 9% to about 15%, or about 12% to about 15% of the cross-sectional area of the stabilization column.

[0091] In some embodiments, the method may include determining, using a control system, the initial operating conditions of the stabilization system to obtain a stabilized crude oil stream having an RVP within a predetermined range. In some applications, the initial operation conditions of the stabilization system may be determined and set according to a composition of the input stream as well as the recovery and treating conditions of the input stream, as simulated by the control system. In some embodiments, the method may further include adjusting the operating conditions of the stabilization system, using the control system, to account for any variance in the composition of the input stream such that the stabilization system produces an NGL solvent stream and a stabilized crude oil stream that meets a predetermined standard. In some applications the predetermined standard may include an acceptable range for the reid vapor pressure (RVP) of the stabilized crude oil stream.

[0092] In some embodiments, adjusting the operating conditions of the stabilization system may include adjusting the stabilization column to a temperature of about 100° F. to about 800° F. depending on the composition of the input stream. For example, the stabilization system may be operated at a temperature of about 100° F. to about 150° F., about 100° F. to about 200° F., about 100° F. to about 250° F., about 100° F. to about 300° F., about 100° F. to about 350° F., about 100° F. to about 400° F., about 100° F. to about 450° F., about 100° F. to about 500° F., about 100° F. to about 550° F., about 100° F. to about 600° F., about 100° F. to about 650° F., about 100° F. to about 700° F., about 100° F. to about 750° F., about 100° F. to about 800° F., about 150° F. to about 200° F., about 150° F. to about 250° F., about 150° F. to about 300° F., about 150° F. to about 350° F., about 150° F. to about 400° F., about 150° F. to about 450° F., about 150° F. to about 500° F., about 150° F. to about 550° F., about 150° F. to about 600° F., about 150° F. to about 650° F., about 150° F. to about 700° F., about 150° F. to about 750° F., about 150° F. to about 800° F., about 200° F. to about 250° F., about 200° F. to about 300° F., about 200° F. to about 350° F., about 200° F. to about 400° F., about 200° F. to about 450° F., about 200° F. to about 500° F., about 200° F. to about 550° F., about 200° F. to about 600° F., about 200° F. to about 650° F., about 200° F. to about 700° F., about 200° F. to about 750° F., about 200° F. to about 800° F., about 250° F. to about 300° F., about 250° F. to about 350° F., about 250° F. to about 400° F., about 250° F. to about 450° F., about 250° F. to about 500° F., about 250° F. to about 550° F., about 250° F. to about 600° F., about 250° F. to about 650° F., about 250° F. to about 700° F., about 250° F. to about 750° F., about 250° F. to about 800° F., about 300° F. to about 350° F., about 300° F. to about 400° F., about 300° F. to about 450° F., about 300° F. to about 500° F., about 300° F. to about 550° F., about 300° F. to about 600° F., about 300° F. to about 650° F., about 300° F. to about 700° F., about 300° F. to about 750° F., about 300° F. to about 800° F., about 350° F. to about 400° F., about 350° F. to about 450° F., about 350° F. to about 500° F., about 350° F. to about 550° F., about 350° F. to about 600° F., about 350° F. to about 650° F., about 350° F. to about 700° F., about 350° F. to about 750° F., about 350° F. to about 800° F., about 400° F. to about 450° F., about 400° F. to about 500° F., about 400° F. to about 550° F., about 400° F. to about 600° F., about 400° F. to about 650° F., about 400° F. to about 700° F., about 400° F. to about 750° F., about 400° F. to about 800° F., about 450° F. to about 500° F., about 450° F. to about 550° F., about 450° F. to about 600° F., about 450° F. to about 650° F., about 450° F. to about 700° F., about 450° F. to about 750° F., about 450° F. to about 800° F., about 500° F. to about 550° F., about 500° F. to about 600° F., about 500° F. to about 650° F., about 500° F. to about 700° F., about 500° F. to about 750° F., about 500° F. to about 800° F., about 550° F. to about 600° F., about 550° F. to about 650° F., about 550° F. to about 700° F., about 550° F. to about 750° F., about 550° F. to about 800° F., about 600° F. to about 650° F., about 600° F. to about 700° F., about 600° F. to about 750° F., about 600° F. to about 800° F., about 650° F. to about 700° F., about 650° F. to about 750° F., about 650° F. to about 800° F., about 700° F. to about 750° F., about 700° F. to about 800° F., about 750° F. to about 800° F., or about 800° F. to about 800° F. Alternatively, the stabilization system may be operated at a temperature of about 200° F. to about 750° F., depending on the composition of the input stream. In yet another alternate embodiment, the stabilization system may be operated at a temperature of about 100° F. to about 600° F. In further embodiments, adjusting the operating conditions of the stabilization system may include adjusting the stabilization system to a pressure of about 100 psig to about 600 psig, depending on the composition of the input stream. For example, the stabilization system may be operated at a pressure of about 100 psig to about 150 psig, about 100 psig to about 200 psig, about 100 psig to about 250 psig, about 100 psig to about 300 psig, about 100 psig to about 350 psig, about 100 psig to about 400 psig, about 100 psig to about 450 psig, about 100 psig to about 500 psig, about 100 psig to about 550 psig, about 100 psig to about 600 psig, about 150 psig to about 200 psig, about 150 psig to about 250 psig, about 150 psig to about 300 psig, about 150 psig to about 350 psig, about 150 psig to about 400 psig, about 150 psig to about 450 psig, about 150 psig to about 500 psig, about 150 psig to about 550 psig, about 150 psig to about 600 psig, about 200 psig to about 250 psig, about 200 psig to about 300 psig, about 200 psig to about 350 psig, about 200 psig to about 400 psig, about 200 psig to about 450 psig, about 200 psig to about 500 psig, about 200 psig to about 550 psig, about 200 psig to about 600 psig, about 250 psig to about 300 psig, about 250 psig to about 350 psig, about 250 psig to about 400 psig, about 250 psig to about 450 psig, about 250 psig to about 500 psig, about 250 psig to about 550 psig, about 250 psig to about 600 psig, about 300 psig to about 350 psig, about 300 psig to about 400 psig, about 300 psig to about 450 psig, about 300 psig to about 500 psig, about 300 psig to about 550 psig, about 300 psig to about 600 psig, about 350 psig to about 400 psig, about 350 psig to about 450 psig, about 350 psig to about 500 psig, about 350 psig to about 550 psig, about 350 psig to about 600 psig, about 400 psig to about 450 psig, about 400 psig to about 500 psig, about 400 psig to about 550 psig, about 400 psig to about 600 psig, about 450 psig to about 500 psig, about 450 psig to about 550 psig, about 450 psig to about 600 psig, about 500 psig to about 550 psig, about 500 psig to about 600 psig, or about 550 psig to about 600 psig. In one particular example, the stabilization system may be operated at a pressure of about 200 psig to about 400 psig. In some embodiments, adjusting the pressure of the stabilization system may be performed using a pump in communication with and operable to maintain the pressure of the stabilization column.

[0093] In some embodiments, the stabilization column may include a housing formed from a carbon steel-based alloy suitable for elevated temperature and pressure service, including low-alloy chromium-molybdenum (Cr—Mo) steels. By way of example, the vessel may be constructed from a Cr—Mo alloy steel having enhanced creep resistance and high-temperature strength sufficient for continuous operation at temperatures of approximately 800° F. and internal pressures of approximately 600 psig, thereby maintaining structural integrity and pressure containment under sustained thermal and mechanical loading conditions.

[0094] As mentioned above, an important aspect of the present method is simulating the composition of a source reservoir using a reservoir simulator calibrated to field test data to account for the wide variance in reservoir composition between wells and high volatility of the fluids produced by EOR projects. Accordingly, in some embodiments, the control system may include a reservoir simulator that may be used to simulate the composition of a well or reservoir from which the input stream is sourced. Alternatively, the reservoir simulator may be used to simulate the composition of the input stream itself. In another alternative, the composition of the input stream may be known or determined by testing and manually or automatically provided to the control system. The control system may then be used to determine the optimal operating conditions (e.g. temperature and pressure) for the stabilization system to produce a crude oil stream having an RVP within a predetermined range based on the composition data received by the control system or determined by the reservoir simulator. In an alternative, the operating conditions of the stabilization system may be determined and adjusted manually. In some embodiments, the control system may be used to simulate the composition of the input stream on a continuous basis and adaptively adjust the pressure and temperature of the stabilization system in response to changes in the composition of the input stream. In other embodiments, the control system may be used to only simulate the composition of the input stream to determine the optimal operating conditions of the stabilization system (e.g. optimal initial temperature and initial pressure of the stabilization column).

[0095] In some embodiments, the control system may include one or more models for determining the optimal operating conditions of the stabilization system based on the composition and physical properties and conditions of the input stream. In some embodiments, the method may further include manually selecting a startup operating model from a plurality of startup operating models to be used by the control system based on the historian of the control system. In further embodiments, the method may further include selecting the startup operating model based on where the input stream is sourced from such that the stabilization system may account for a compositional variance in the input stream and separate out a stabilized crude oil stream that has an RVP within a predetermined range. In yet further embodiments, one or more models of the control system may be used to determine a first temperature and pressure of the stabilization system required to separate out a stabilized crude oil stream that has an RVP within a predetermined range.

[0096] The models may be or include: regression models (e.g., linear, regularized, partial least squares, and / or nonlinear regression), tree-based models (e.g., decision trees, random forests, gradient-boosted trees), support vector regression and other kernel-based regression methods (e.g., Gaussian process regression), Bayesian regression methods, neural network models (e.g., feed-forward networks, deep neural networks, and / or transformer-based networks), and / or any other suitable model, machine learning algorithm, or methodology. In some implementations, the model may further include an equation-based model (e.g., weighted equations or other parametric functional forms) and / or a hybrid model that combines one or more of the foregoing data-driven models with deterministic process relationships (e.g., mass / energy-balance constraints, thermodynamic property relationships, and / or column performance correlations) to improve predictive accuracy and enforce physically feasible operating conditions.

[0097] In some embodiments, the one or more models of the control system may be trained to determine the optimal pressure and temperature of the stabilization system based on the composition and physical properties and / or conditions of the input stream. The one or more models may be trained on existing composition data and manually assigned operating parameters. Alternatively, the models may be iteratively trained on existing composition data and operating parameters that have been randomly assigned. In further embodiments, the models may be trained using: self-supervised learning, semi-supervised learning, supervised learning, unsupervised learning, reinforcement learning, transfer learning, Bayesian optimization, positive-unlabeled learning, using backpropagation methods, and / or otherwise learned. The model can be learned or trained on: labeled data (e.g., data labeled with the target label), unlabeled data, positive training sets (e.g., a set of data with true positive labels, negative training sets (e.g., a set of data with true negative labels), and / or any other suitable set of data. In some applications, the one or more models may be trained on a continuous basis based on a degree of error between the RVP of the stabilized crude oil stream produced by the stabilization system and the acceptable predetermined range. In other applications, the one or more models may be iteratively trained prior to use within the system.

[0098] During separation of the input stream within the stabilization system, the input stream flows downward through packing disposed within a stabilization column while lighter, more volatile hydrocarbon components are vaporized to form an overhead NGL solvent stream. In some embodiments, the NGL solvent stream comprises one or more of ethane (C2), propane (C3), butane (C4), and pentane (C5) and may further include one or more impurities including nitrogen (N2), helium (He), carbon dioxide (CO2), hydrogen sulfide (H2S), hydrogen (H2), or combinations thereof. In some embodiments, the method may include heating the input stream, using a heater, to vaporize the lighter NGL components using one or more heating through one or more heating mechanisms, including catalytic heating, electric immersion or resistive heating, electric immersion or resistive heating employing pulse-width modulation, internal heat integration within the system, a direct-fired heating system utilizing the NGL solvent stream as a fuel source, or a direct-fired heating system utilizing a utility gas stream extracted from the NGL solvent stream as a fuel source.

[0099] After separation of the NGL solvent stream from the input stream, the method may include further stabilizing a remaining liquid portion of the input stream as it continues to flow downward through the stabilization column to produce a stabilized crude oil stream. The stabilized crude oil stream may be primarily composed of pentane-plus (C5+) hydrocarbons and may have a reid vapor pressure within a predetermined or contracted specification range. In some embodiments, the stabilized crude oil stream may includes hydrocarbons having molecular weights equal to or greater than that of propane, and may further include one or more impurities.

[0100] In some embodiments, the method may further include recovering the stabilized crude oil stream from the base of the stabilization column and cooling the stabilized crude oil stream using an ambient air cooler. In further embodiments, the method may also include providing the cooled stabilized crude oil stream for storage, transportation, or sale as a stabilized hydrocarbon product.

[0101] Due to variance in reservoir and input stream composition among different sources of Y-Grade or production streams, and uncertainty in the precise composition of such streams, the stabilized crude oil stream exiting the stabilization column may, in some instances, exhibit a reid vapor pressure (RVP) outside a predetermined or contracted specification range. To address such conditions, the present method may further include measuring the RVP of the stabilized crude oil stream using an RVP measurement device and determining if the RVP of the stabilized crude oil stream falls outside of a predetermined range. Where the RVP does fall outside of the predetermined range, the method may further include recycling the stabilized crude oil stream back into the stabilization system for further processing using a recycle loop. In some applications, recycling the stabilized crude oil stream may include recycling the entire stabilized crude oil stream. Alternatively, only a portion of the stabilized crude oil stream may be recycled.

[0102] In some embodiments, the method may include splitting the recycled crude oil stream into a first portion and a second portion of the recycled crude oil stream. The first portion of the recycled crude oil stream may be fed to the base of the stabilization system. In further embodiments, the method may include heating the first portion using the heater prior to the first portion being fed to the base of the stabilization column. The heater may be used to heat the first portion to a temperature determined by the control system prior to feeding the first portion to the base of the stabilization column such that the stabilization system produces a stabilized crude oil stream with an RVP that falls within the predetermined range.

[0103] Some aspects of the method may further include feeding the second portion of the recycled crude oil stream to an upper portion of the stabilization column. In some embodiments, the second portion may be fed to the top of the stabilization column. In further aspects, the method may include selectively adjusting the relative proportions of the first portion and the second portion over a range of about 0% to about 100% based on a measured or desired temperature profile within the stabilization column, such that distribution of the recycled crude oil stream is controlled to maintain thermal stability, vapor-liquid equilibrium, and vapor pressure compliance.

[0104] As mentioned above, the method may include feeding the first portion of the stabilized crude oil stream to the heater of the stabilization system. In some embodiments, the method may further include heating the recycled stabilized crude oil stream using the heater prior to feeding the recycled stabilized crude oil stream back into the stabilization system to vaporize the lighter NGL components (C2 / C3 / C4 / C5) out of the crude oil stream. In some embodiments, the heater may be used to heat the recycled stabilized crude oil stream to a temperature of about 500° F. to about 800° F. For example, the reflux heater may be used to heat the recycled stabilized crude oil stream to a temperature of about 500° F. to about 525° F., about 500° F. to about 550° F., about 500° F. to about 575° F., about 500° F. to about 600° F., about 500° F. to about 625° F., about 500° F. to about 650° F., about 500° F. to about 675° F., about 500° F. to about 700° F., about 500° F. to about 725° F., about 500° F. to about 750° F., about 500° F. to about 775° F., about 500° F. to about 800° F., about 525° F. to about 550° F., about 525° F. to about 575° F., about 525° F. to about 600° F., about 525° F. to about 625° F., about 525° F. to about 650° F., about 525° F. to about 675° F., about 525° F. to about 700° F., about 525° F. to about 725° F., about 525° F. to about 750° F., about 525° F. to about 775° F., about 525° F. to about 800° F., about 550° F. to about 575° F., about 550° F. to about 600° F., about 550° F. to about 625° F., about 550° F. to about 650° F., about 550° F. to about 675° F., about 550° F. to about 700° F., about 550° F. to about 725° F., about 550° F. to about 750° F., about 550° F. to about 775° F., about 550° F. to about 800° F., about 575° F. to about 600° F., about 575° F. to about 625° F., about 575° F. to about 650° F., about 575° F. to about 675° F., about 575° F. to about 700° F., about 575° F. to about 725° F., about 575° F. to about 750° F., about 575° F. to about 775° F., about 575° F. to about 800° F., about 600° F. to about 625° F., about 600° F. to about 650° F., about 600° F. to about 675° F., about 600° F. to about 700° F., about 600° F. to about 725° F., about 600° F. to about 750° F., about 600° F. to about 775° F., about 600° F. to about 800° F., about 625° F. to about 650° F., about 625° F. to about 675° F., about 625° F. to about 700° F., about 625° F. to about 725° F., about 625° F. to about 750° F., about 625° F. to about 775° F., about 625° F. to about 800° F., about 650° F. to about 675° F., about 650° F. to about 700° F., about 650° F. to about 725° F., about 650° F. to about 750° F., about 650° F. to about 775° F., about 650° F. to about 800° F., about 675° F. to about 700° F., about 675° F. to about 725° F., about 675° F. to about 750° F., about 675° F. to about 775° F., about 675° F. to about 800° F., about 700° F. to about 725° F., about 700° F. to about 750° F., about 700° F. to about 775° F., about 700° F. to about 800° F., about 725° F. to about 750° F., about 725° F. to about 775° F., about 725° F. to about 800° F., about 750° F. to about 775° F., about 750° F. to about 800° F., or about 775° F. to about 800° F. In an alternative embodiment, the reflux heater may be used to heat the recycled stabilized crude oil stream to a temperature of about 100° F. to about 800° F. In some aspects, the reflux heater may heat the recycled stabilized crude oil stream using a catalytic process, an electrical emersion heater and / or resistive heater, an electrical emersion heater and / or resistive heater utilizing pulse width modulation, internal system heat integration, a direct-fired heating system using the NGL solvent stream as a fuel source, or a direct-fired heating system using a utility gas stream (e.g. methane) extracted from the NGL solvent stream as a fuel source.

[0105] In further embodiments, the method may further include determining, using the control system, required operating conditions by the stabilization system to obtain a stabilized crude oil stream with an RVP that falls within a predetermined range. For example, the method may further include determining, using the control system, a required temperature and a required pressure of the stabilization system to obtain a stabilized crude oil stream with an RVP that falls within a predetermined range. Where the RVP of the stabilized crude oil stream falls outside of the predetermined range, the method may further include adjusting the operating conditions of the stabilization system to the required operating conditions determined using the control system. In some embodiments, the required operating conditions may be determined using the control system based on the composition of the input stream and / or RVP of the recycled stabilized crude oil stream as the optimal operating conditions to achieve an RVP of the stabilized crude oil stream within the predetermined range. In other applications, the one or more models may be used to measure the RVP of the stabilized crude oil stream and determine an updated or required temperature and pressure of the stabilization system on a periodic basis. In some aspects, the RVP of the stabilized crude oil stream may be measured once per every about 30 seconds to about 6 hours. For example, RVP of the stabilized crude oil stream may be measured once per every about 30 seconds to about 1 minute, about 30 seconds to about 5 minutes, about 30 seconds to about 20 minutes, about 30 seconds to about 40 minutes, about 30 seconds to about 1 hour, about 30 seconds to about 2 hours, about 30 seconds to about 3 hours, about 30 seconds to about 4 hours, about 30 seconds to about 5 hours, about 30 seconds to about 6 hours, about 1 minute to about 5 minutes, about 1 minute to about 20 minutes, about 1 minute to about 40 minutes, about 1 minute to about 1 hour, about 1 minute to about 2 hours, about 1 minute to about 3 hours, about 1 minute to about 4 hours, about 1 minute to about 5 hours, about 1 minute to about 6 hours, about 5 minutes to about 20 minutes, about 5 minutes to about 40 minutes, about 5 minutes to about 1 hour, about 5 minutes to about 2 hours, about 5 minutes to about 3 hours, about 5 minutes to about 4 hours, about 5 minutes to about 5 hours, about 5 minutes to about 6 hours, about 20 minutes to about 40 minutes, about 20 minutes to about 1 hour, about 20 minutes to about 2 hours, about 20 minutes to about 3 hours, about 20 minutes to about 4 hours, about 20 minutes to about 5 hours, about 20 minutes to about 6 hours, about 40 minutes to about 1 hour, about 40 minutes to about 2 hours, about 40 minutes to about 3 hours, about 40 minutes to about 4 hours, about 40 minutes to about 5 hours, about 40 minutes to about 6 hours, about 1 hour to about 2 hours, about 1 hour to about 3 hours, about 1 hour to about 4 hours, about 1 hour to about 5 hours, about 1 hour to about 6 hours, about 2 hours to about 3 hours, about 2 hours to about 4 hours, about 2 hours to about 5 hours, about 2 hours to about 6 hours, about 3 hours to about 4 hours, about 3 hours to about 5 hours, about 3 hours to about 6 hours, about 4 hours to about 5 hours, about 4 hours to about 6 hours, or about 5 hours to about 6 hours. In some variants of the present methods, the temperature and pressure of the stabilization system may be adjusted to the second temperature and second pressure manually. Once the stabilized crude oil stream is determined to have an RVP that falls within the stabilized crude oil stream, the stabilized crude oil stream may be fed into a storage tank or transportation container / vehicle for sale as a commodity product.

[0106] In some embodiments, the method may include stabilizing the crude oil stream from the input stream at elevated pressure and temperature operating conditions within the stabilization column, including temperatures of up to about 800° F. and pressures of up to about 600 psig, such that a crude oil stream is stabilized to a target predetermined range of RVP in a single high-pressure, high-temperature stabilization step. Under these conditions, light hydrocarbon components are sufficiently removed such that, upon subsequent cooling of the stabilized crude oil stream to ambient conditions, the stabilized crude oil remains subcooled relative to its bubble point and does not outgas during transfer to storage. This results in improved stabilization efficiency, increased liquid recovery, and reduced emissions associated with storage tank off-gassing. In some embodiments, the method may include directing the stabilized crude oil stream directly to a pipeline, bypassing intermediate storage, wherein the pipeline transport functions as a final stabilization stage prior to delivery while maintaining compliance with the specified vapor pressure requirements.

[0107] In some embodiments, the predetermined range of RVP may be about 6 psia to about 12 psia. For example, the predetermined range may be about 6 psia to about 7 psia, about 6 psia to about 8 psia, about 6 psia to about 9 psia, about 6 psia to about 10 psia, about 6 psia to about 11 psia, about 6 psia to about 12 psia, about 7 psia to about 8 psia, about 7 psia to about 9 psia, about 7 psia to about 10 psia, about 7 psia to about 11 psia, about 7 psia to about 12 psia, about 8 psia to about 9 psia, about 8 psia to about 10 psia, about 8 psia to about 11 psia, about 8 psia to about 12 psia, about 9 psia to about 10 psia, about 9 psia to about 11 psia, about 9 psia to about 12 psia, about 10 psia to about 11 psia, about 10 psia to about 12 psia, or about 11 psia to about 12 psia. In one particular example, the stabilization process may be performed at elevated pressure and temperature operating conditions to stabilize the crude oil stream to a target RVP of about 9 psia. In some embodiments, the target RVP or predetermined range of RVP may be determined based on where the stabilized crude oil of the stabilized crude oil stream is marketed as well as other economic factors. For example, the target RVP or predetermined range of RVP may be lowered to drive more volume to the solvent tank where an operator wants to generate a larger volume of NGL solvent. As another example, the target RVP or predetermined range of RVP may be raised to maximize crude oil sales where the operator has available “dry” crude to blend with.

[0108] In some embodiments, it may be beneficial for the method to further include cooling the stabilized crude oil stream using an ambient cooler following extracting the stabilized crude oil stream from the stabilization column.

[0109] In some embodiments, the NGL solvent stream separated from the stabilized crude oil stream may rise to and exit at the top of the stabilization system. Because the NGL solvent stream is gaseous at this point, it may be desirable for the method to include a condensing the NGL solvent stream using a condenser system. The condenser system may be used to condense the NGL solvent stream such that it may be used as a liquid solvent for injection in EOR operations. In some embodiments, the condenser system may include a compressor. The compressor may be used to compress the gaseous NGL solvent stream exiting the stabilization system to a pressure suitable condensing propane and butane present in the NGL solvent stream. In some applications the condenser system may further include a cooler that may be used to condense the compressed gaseous NGL solvent to produce a condensed NGL solvent stream comprising propane and butane. In yet further embodiments, the condenser system may include only a cooler operable to condense the gaseous NGL solvent to produce the condensed NGL solvent stream. The cooler of the condenser system may, in some embodiments, be an air cooler, a water cooler, a heat exchanger suitable for recycling the heat of the gaseous NGL solvent stream, or any other suitable heat exchanger or cooler. In other embodiments, the condenser system may include an inlet pump and an overhead condenser in fluid communication with the stabilization system. The overhead condenser may be operable to condense the gaseous NGL solvent stream using mechanical refrigeration, membranes, or ambient air cooling to produce the liquid NGL solvent stream for injection in EOR operations. The remaining gaseous portion of the gaseous NGL solvent stream may include methane, ethane, any light impurities separated from the stabilized crude oil stream by the stabilization system, or a combination thereof. In further applications, the compressor and cooler of the condenser system may be operable to compress and cool the gaseous NGL solvent stream to produce a liquid NGL solvent stream including ethane, propane, and butane. In this case, the remaining gaseous portion may include methane, any light impurities separated from the stabilized crude oil stream by the stabilization system, or a combination thereof. In some aspects, the remaining gaseous components may be separated from the condensed NGL solvent stream and sold as a utility gas or used internally within the system as a utility gas.

[0110] The present method may, in further embodiments, include feeding the condensed NGL solvent stream to a solvent storage tank operable to store the condensed NGL solvent stream for sale as an injectable solvent for EOR or for internal recycle to the stabilization system to compensate for deviations in the mass flowrate operating variables beyond a predetermined range. In some embodiments, the method may include monitoring, using the control system, the mass flowrate operating variables of the stabilization system to determine whether the mass flowrate operating variables of the stabilization system do not fall within the predetermined range. The control system may be used to determine the amount of NGL solvent to recyle to the stabilization system based on the mass flowrate operating variables of the stabilization system, the operating conditions of the stabilization system, the RVP of the stabilized crude oil stream, the composition of the input stream, or a combination thereof. In some embodiments, the method may include recycling the portion of the NGL solvent stream such that it is reinjected into the top of the stabilization column. In one particular example, the method may include monitoring the build up of impurities within the stabilization column and heater and injecting a portion of the NGL solvent stream into the stabilization column to flush out the build up of asphaltene and / or paraffin within the stabilization column and heater.

[0111] As a result of the adaptability of the stabilization system via the control system of the present method in handling the stabilization of Y-Grade of variable compositions, the present system is suitable for stabilizing Y-Grade from various sources. For example, the Y-Grade or unfractionated NGLs of the input stream may be trucked in, sourced from a pipeline, sourced from a storage tank, directly obtained from an onsite 3 phase production separator, or directly obtained from the output of a gas conditioning facility. Where the presently disclosed systems are installed onsite at a gas conditioning plant, the input stream may include the unfractionated NGL or Y-Grade produced by the gas conditioning plant and may further include unfractionated NGL or Y-Grade obtained from one or more additional sources. In some embodiments, the ancillary equipment of the present methods working in combination with the stabilization system may be dictated by a combination of the operating conditions of the stabilization system and the source from which the input stream is obtained.

[0112] In one particular example, the presently disclosed methods may be employed using a system for stabilizing and separating Y-Grade natural gas liquids (NGLs) may be installed onsite at an operator's lease where the Y-Grade is trucked in as depicted in FIG. 1. In such a case, the composition of the input stream may be similar to the exemplary Y-Grade composition presented in Table 1. Referring to FIG. 1, the system may further include a Y-Grade storage tank (001) to supply the input stream to the stabilization system. In some embodiments, the Y-Grade may be stored within the Y-Grade storage tank at a temperature of about 32° F. to about 130° F. For example, the Y-Grade may be stored within the Y-Grade storage tank at a temperature of about 32° F. to about 40° F., about 32° F. to about 50° F., about 32° F. to about 60° F., about 32° F. to about 70° F., about 32° F. to about 80° F., about 32° F. to about 90° F., about 32° F. to about 100° F., about 32° F. to about 110° F., about 32° F. to about 120° F., about 32° F. to about 130° F., about 40° F. to about 50° F., about 40° F. to about 60° F., about 40° F. to about 70° F., about 40° F. to about 80° F., about 40° F. to about 90° F., about 40° F. to about 100° F., about 40° F. to about 110° F., about 40° F. to about 120° F., about 40° F. to about 130° F., about 50° F. to about 60° F., about 50° F. to about 70° F., about 50° F. to about 80° F., about 50° F. to about 90° F., about 50° F. to about 100° F., about 50° F. to about 110° F., about 50° F. to about 120° F., about 50° F. to about 130° F., about 60° F. to about 70° F., about 60° F. to about 80° F., about 60° F. to about 90° F., about 60° F. to about 100° F., about 60° F. to about 110° F., about 60° F. to about 120° F., about 60° F. to about 130° F., about 70° F. to about 80° F., about 70° F. to about 90° F., about 70° F. to about 100° F., about 70° F. to about 110° F., about 70° F. to about 120° F., about 70° F. to about 130° F., about 80° F. to about 90° F., about 80° F. to about 100° F., about 80° F. to about 110° F., about 80° F. to about 120° F., about 80° F. to about 130° F., about 90° F. to about 100° F., about 90° F. to about 110° F., about 90° F. to about 120° F., about 90° F. to about 130° F., about 100° F. to about 110° F., about 100° F. to about 120° F., about 100° F. to about 130° F., about 110° F. to about 120° F., about 110° F. to about 130° F., about 120° F. to about 130° F., or about 130° F. to about 130° F. In further embodiments, the Y-Grade may be stored within the Y-Grade storage tank at a pressure of about 50 psig to about 225 psig. For example, the Y-Grade may be stored within the Y-Grade storage tank at a pressure of about 50 psig to about 75 psig, about 50 psig to about 100 psig, about 50 psig to about 125 psig, about 50 psig to about 150 psig, about 50 psig to about 175 psig, about 50 psig to about 200 psig, about 50 psig to about 225 psig, about 75 psig to about 100 psig, about 75 psig to about 125 psig, about 75 psig to about 150 psig, about 75 psig to about 175 psig, about 75 psig to about 200 psig, about 75 psig to about 225 psig, about 100 psig to about 125 psig, about 100 psig to about 150 psig, about 100 psig to about 175 psig, about 100 psig to about 200 psig, about 100 psig to about 225 psig, about 125 psig to about 150 psig, about 125 psig to about 175 psig, about 125 psig to about 200 psig, about 125 psig to about 225 psig, about 150 psig to about 175 psig, about 150 psig to about 200 psig, about 150 psig to about 225 psig, about 175 psig to about 200 psig, about 175 psig to about 225 psig, or about 200 psig to about 225 psig. Depending on the pressure in the Y-Grade storage tank the present system may further include a transfer pump (002) operable to deliver the unfractionated NGL of the input stream to the stabilization system (003). Where the pressure within the Y-Grade storage tank is high enough, the input stream may feed to the stabilization system. Where the pressure within the Y-Grade storage tank is lower, the input stream may be pumped to the stabilization system using the transfer pump (002).

[0113] Upon being fed to the stabilization system (003), the input stream may be separated into two streams: the heavier pentane plus stabilized crude oil stream and the lighter ethane to butane (C2 to C4) components that make up the NGL solvent stream. In some embodiments, NGL solvent stream may further include pentane (C5). For example, the NGL solvent stream may include pentane in an amount of about 0 mole % to about 10 mole % of the total composition of the NGL solvent stream. According to some aspects, the pentane plus (C5+) components may flow from the stabilization column to an oil storage tank (004) or directly to an oil sales pipeline. In some embodiments, the lighter NGL solvent stream of ethane, propane, butanes, and pentane (C2-C5) may exit the stabilization system in a liquid state. The liquid NGL solvent stream may be delivered to the Solvent Storage Tank (005) for storage.

[0114] According to further aspects, the NGL solvent stream may exit the stabilization column in a gaseous state. In some embodiments, the gaseous NGL solvent stream may include gaseous ethane, propane, butane, and pentane (C2C5). The condensing system of the stabilization system may be used to condense and separate the propane and butane from the remaining gaseous components of the NGL solvent stream. In some aspects the remaining gaseous components of the NGL solvent stream may include gaseous ethane and propane. In order to condense the remaining propane within the gaseous components of the NGL solvent stream, the method may further include condensing the remaining gaseous components of the NGL solvent stream using a cooling system (006) in fluid communication with the top of the stabilization system. The gaseous portion of the NGL solvent stream may be directed into the suction of a small compressor of the cooling system, for compression to a pressure amenable for condensing the gaseous portion. The method may further include cooling and condensing the compressed remaining gaseous portion of the NGL solvent stream using an air cooler operable such that predominantly propane (C3), is condensed from the gaseous portion and flowed to the solvent storage tank (005). The liquid NGL solvent that is stored within the solvent stream may then be sold or used as a well injectant for onsite EOR operations. Alternatively, the liquid NGL solvent may be recycled to the stabilization column to account for deviations in the mass flowrate operating variables of the system.

[0115] In some applications, the method may include the uncondensed gas from the input stream by the present system. In one embodiment, the uncondensed gas may be a utility gas predominantly including methane. For example, the utility gas (007) may be separated from the gaseous NGL stream in the stabilization system (003) and / or in the cooling system (006). In some embodiments, it may be desirable for the method to include utilizing the liberated utility gas as a utility gas for the on-site equipment. By using the utility gas liberated by both systems (003) and (006) as a utility gas on site, the present methods may reduce the carbon emissions from a gas conditioning plant because of the cleaner burn of methane compared to that of the rich gas mixture, including condensates that is conventionally used within the industry for onsite fuel utilization. Additional carbon emission reduction may also be attributed to reduced tanker truck transportation related to both volumes and mileage.

[0116] In another embodiment, as depicted in FIG. 2A, the Y-Grade input of the present method may be supplied by a Y-Grade pipeline (008). Typical operating pressures for Y-Grade pipelines fall around about 400 psi to about 600 psi with a combined concentration of methane and ethane being greater than about 30 mole %. In such a case, it may be beneficial for the method to include reducing the pressure of the input stream at an orifice (009), or another device designed to achieve a pressure drop of the input stream upstream from the stabilization system. In some embodiments, the pressure of the input stream delivered by pipeline may require a reduction in pressure to effectively liberate a high concentration of ethane gas from the input stream. Where the pressure drop liberates a high concentration of ethane gas from the input stream, the method may further include separating the gaseous ethane (C2) from the input stream using a gas / fluid separator (010) installed upstream of the stabilization system (011). In some embodiments, the gas / fluid separator may be used to separate the gaseous ethane (C2) from the input stream such that it may be sold as a product stream. Alternatively, the rich ethane gas coming off the gas separator may be returned to the Y-Grade pipeline. Because the gas / fluid separator removes a large portion of the methane and ethane content of the input stream, the composition of the input stream fed to the stabilization system (011) may be highly rich in propane butane, and pentane (C3, C4, and C5) with the majority of the liquids in the stream being delivered to the Solvent Storage Tank (014) following processing in the stabilization system. According to such embodiments as depicted in FIG. 2A, the resulting pentane plus (C5+) stabilized crude oil stream flowing to the oil storage tank (012) may represent less than one third of the total liquids fed to the stabilization system in the input stream.

[0117] Variations of this embodiment, as depicted in FIG. 2B, may be operated at a pressure similar to the pressure of the Y-Grade pipeline supply. This permits the ethane (C2) to remain in a liquid state, consequently increasing the solvent supply volume. In the scenario depicted by FIG. 2B, the method may include buffering the flow of the input stream to the stabilization using a capacitor (016) for the Y-Grade input stream upstream of the stabilization system (017) as necessary. According to some aspects of the present system, the stabilization system may be used to deliver liquid ethane, propane, butane, and pentane to the solvent storage tank (020). Any off-gas from the stabilization system may be compressed and condensed to a liquid (019) for storage at the solvent storage tank (020).

[0118] Referring to FIG. 3, in further embodiments, the presently disclosed method may be installed on a neutral site and receive a Y-Grade supply from tanker trucks from multiple locations (022). This may require a larger capacity stabilization system which may in turn provide an even greater carbon emission reduction attributed to further reduction in tanker truck mileage.

[0119] In yet another embodiment, the method may be performed on the site of an oil and gas producer who owns and operates their own gas conditioning plant(s) which generates Y-Grade. In the current market, this Y-Grade is typically sold to midstream refiners for 30% to 40% of WTI Oil Pricing. Producers may therefore benefit from the implementation of the present methods by further extracting additional pentane plus (C5+) from the Y-Grade to augment their oil sales stream and by supplying their own solvent for well stimulation treatments and EOR projects. This represents a significant cost savings and extremely robust economics for these applications. In some embodiments, producers may control the operation of the stabilization system to obtain an optimum split of butane (C4) and pentane (C5) going to the NGL solvent and stabilized crude oil streams respectively. In further embodiments, the propane, butane, and pentane (C3, C4, and C5) produced by the present method may be reinjected into a well or reservoir for EOR operations. Not only may the reinjection of propane, butane, and pentane (C3, C4, and C5) for EOR result in an improved extraction of crude oil and dry gas from the well, the reinjection may result in the sequestration of the C3, C4, and C5 in the reservoir, thus significantly reducing an operator's carbon intensity.

[0120] In further embodiments of the present method, the NGL solvent streams produced by the present method may be used in EOR projects. In some embodiments, the NGL solvent stream may be used alone or in combination with Y-Grade in EOR projects by injecting the NGL solvent stream and / or Y-Grade into the well or reservoir where the method is performed. Referring to FIG. 4, in some embodiments, the present method may be performed using a stabilization system incorporated into an NGL recycling system operable to separate NGL solvent stream products (C2-C5) from well production (024) and reinject the NGL solvent stream products back into the well for EOR (027). When the NGL solvent stream is injected downhole in a well, the returned produced fluids from the well(s) (024) may require initial processing prior to being fed to the stabilization system. Accordingly, the well production system may include a low pressure three phase separator (025) operable to separate the produced well fluid into three streams: wet gas, volatile oil, and water. Where the well production system is used in combination with the recycling of the NGL solvent stream produced by the stabilization system, the method may include using the NGL solvent stream as a liquid solvent injectant stream comprised predominantly of propane and butane (C3 and C4). In some embodiments, the method may include using the NGL solvent stream as a liquid solvent injectant stream comprised predominantly of C3 and C4, in addition to about 0 mole % to about 10 mole % of pentane (C5). For example, the NGL solvent stream may be used as a liquid solvent injectant stream comprising about 0 mole % to about 1 mole %, about 0 mole % to about 2 mole %, about 0 mole % to about 3 mole %, about 0 mole % to about 4 mole %, about 0 mole % to about 5 mole %, about 0 mole % to about 6 mole %, about 0 mole % to about 7 mole %, about 0 mole % to about 8 mole %, about 0 mole % to about 9 mole %, about 0 mole % to about 10 mole %, about 1 mole % to about 2 mole %, about 1 mole % to about 3 mole %, about 1 mole % to about 4 mole %, about 1 mole % to about 5 mole %, about 1 mole % to about 6 mole %, about 1 mole % to about 7 mole %, about 1 mole % to about 8 mole %, about 1 mole % to about 9 mole %, about 1 mole % to about 10 mole %, about 2 mole % to about 3 mole %, about 2 mole % to about 4 mole %, about 2 mole % to about 5 mole %, about 2 mole % to about 6 mole %, about 2 mole % to about 7 mole %, about 2 mole % to about 8 mole %, about 2 mole % to about 9 mole %, about 2 mole % to about 10 mole %, about 3 mole % to about 4 mole %, about 3 mole % to about 5 mole %, about 3 mole % to about 6 mole %, about 3 mole % to about 7 mole %, about 3 mole % to about 8 mole %, about 3 mole % to about 9 mole %, about 3 mole % to about 10 mole %, about 4 mole % to about 5 mole %, about 4 mole % to about 6 mole %, about 4 mole % to about 7 mole %, about 4 mole % to about 8 mole %, about 4 mole % to about 9 mole %, about 4 mole % to about 10 mole %, about 5 mole % to about 6 mole %, about 5 mole % to about 7 mole %, about 5 mole % to about 8 mole %, about 5 mole % to about 9 mole %, about 5 mole % to about 10 mole %, about 6 mole % to about 7 mole %, about 6 mole % to about 8 mole %, about 6 mole % to about 9 mole %, about 6 mole % to about 10 mole %, about 7 mole % to about 8 mole %, about 7 mole % to about 9 mole %, about 7 mole % to about 10 mole %, about 8 mole % to about 9 mole %, about 8 mole % to about 10 mole %, or about 9 mole % to about 10 mole % of C5. In some embodiments, the liquid NGL solvent stream may be used for EOR injection using a high recovery ratio from about 50% to about 100%. For example, the NGL solvent stream may be used for EOR injection using a high recovery ration from about 50% to about 55%, about 50% to about 60%, about 50% to about 65%, about 50% to about 70%, about 50% to about 75%, about 50% to about 80%, about 50% to about 85%, about 50% to about 90%, about 50% to about 95%, about 50% to about 100%, about 55% to about 60%, about 55% to about 65%, about 55% to about 70%, about 55% to about 75%, about 55% to about 80%, about 55% to about 85%, about 55% to about 90%, about 55% to about 95%, about 55% to about 100%, about 60% to about 65%, about 60% to about 70%, about 60% to about 75%, about 60% to about 80%, about 60% to about 85%, about 60% to about 90%, about 60% to about 95%, about 60% to about 100%, about 65% to about 70%, about 65% to about 75%, about 65% to about 80%, about 65% to about 85%, about 65% to about 90%, about 65% to about 95%, about 65% to about 100%, about 70% to about 75%, about 70% to about 80%, about 70% to about 85%, about 70% to about 90%, about 70% to about 95%, about 70% to about 100%, about 75% to about 80%, about 75% to about 85%, about 75% to about 90%, about 75% to about 95%, about 75% to about 100%, about 80% to about 85%, about 80% to about 90%, about 80% to about 95%, about 80% to about 100%, about 85% to about 90%, about 85% to about 95%, about 85% to about 100%, about 90% to about 95%, about 90% to about 100%, or about 95% to about 100%. The recovery ratio may quantify how much of the produced NGL stream is recovered and re-injected back into the well or reservoir.

[0121] In some applications, the wet gas composition obtained from the low pressure three phase separator may predominantly include methane, ethane and propane (C1, C2, and C3). In further applications, the wet gas composition may further include butane (C4). In some applications, the off gas from the production separator may be used to fuel a compression / cooling / condensing system (026) operable to condense the C2, C3, and C4 out of the wet gas stream using multiple stages of compression, cooling and condensation to form the NGL solvent stream. This liquid NGL solvent stream is fed to the solvent storage tank for reinjection (027). In further applications, the volatile oil stream produced by the three-phase separator may include liquid C3 and C4 mixed in with pentane plus (C5+). In some embodiments, the method may include joining the volatile oil stream with the Y-Grade input stream prior to feeding both streams into the stabilization system. In other embodiments, the volatile oil stream may be fed to the stabilization system independently of the Y-Grade input stream. In yet other alternate embodiments, the volatile oil stream may be the only input stream of the method. The Y-Grade input stream and volatile oil stream may be processed by the stabilization system to produce a stabilized crude oil stream and a NGL solvent stream to be further processed as discussed above. In some applications, the stabilized crude oil may be sold or used by a gas production plant operator or a midstream company for blending purposes with other crude supplies. Because of the importance of maintaining the operating conditions of the stabilization system, in some embodiments, the volatile oil stream may be fed to the stabilization column using a transfer pump separate from the transfer pump used for the input stream. In other embodiments, the volatile oil stream may be fed to a volatile oil storage tank for storage prior to being fed to the top of the stabilization column.

[0122] In some aspects, the present method may be performed using a mobile system for stabilizing and separating Y-Grade NGL. Where a mobile system for stabilizing and separating Y-Grade NGL is used to perform the present methods, a cellular service and / or satellite service may be utilized to remotely operate the mobile system. In other aspects, the present system may be stationary. For example, the system may be installed at an oil and gas production facility, a gas conditioning plant, a Y-Grade aggregation terminal, or a distribution facility.5. Examples

[0123] One example of the present system may be operable to process an Y-Grade input stream sourced from a third party midstream gas conditioning storage facility to produce 1) an NGL solvent stream comprising 80% or greater of the combined mole % of ethane (C2), propane (C3), and butane (C4) which may be used in cyclic miscible enhanced oil recovery and stimulation processes and 2) a stabilized crude oil stream comprising 80% or greater by mole % pentane plus (C5+) for oil sales. A small stream of dry gas predominantly comprising methane (C1) is liberated during the stabilization of the crude oil stream which may be used as utility gas for the equipment of the system. The pressure of the incoming Y-Grade supply may range from about 50 psi to about 300 psi to allow for tanker truck transportation. In some embodiments, the pressure of the incoming Y-Grade supply may be less than 50 psi. The ethane content of the incoming Y-Grade stream may be up to about 20 mole %.

[0124] In a second example of the present system, the system may be operable to process a Y-Grade input stream obtained from a storage vessel at a gas Conditioning plant (or NGL plant) of an upstream producer. The predominantly ethane, propane, and butane (C2, C3 and C4) NGL solvent stream separated by the system may be used either for well remediation treatments or in enhanced oil recovery (EOR) operations. When an oil and gas producer uses the C2, C3, and C4 in an EOR project, it may be necessary to incorporate the present system into the NGL recycle system, enabling the system to also treat the highly volatile produced fluids obtained from the well(s) involved in the EOR process. Furthermore, the Y-Grade used in the EOR project may be pumped directly downhole, by-passing the initial phase of stabilization.

[0125] A third example of the present system may be operable to process a Y-Grade input stream obtained from a midstream Y-Grade pipeline (NGL pipeline) to produce 1) a NGL solvent comprising 95% or greater of a combined mole % of ethane (C2), propane (C3), butane (C4), and pentane for use in cyclic miscible enhanced oil recovery processes, and 2) a stabilized crude oil stream comprising 90% or greater by mole % of pentane plus (C5+) for stabilized crude oil sales. The pressure of the incoming Y-Grade supply may be about 400 psi to about 600 psi or greater. The mole % of ethane in the incoming Y-Grade may be about 30% or greater as shown in Table 2 for a typical NGL pipeline composition.

[0126] A fourth example of the present system may be operable to process a Y-Grade input stream obtained from a midstream Y-Grade pipeline, where the Y-Grade is used as an injectant in a cyclic miscible enhanced oil recovery process. When an oil and gas producer uses the Y-Grade in a cyclic miscible enhanced oil recovery process, it may be necessary to incorporate the present system into the NGL recycle system, enabling the stabilization system to also treat the highly volatile fluids produced by the EOR project. In this embodiment, Y-Grade sourced from the pipeline may also be pumped directly downhole, bypassing the initial phase of stabilization.

[0127] A fifth example of the system may be operable to process a Y-Grade input stream obtained from a midstream Y-Grade pipeline (NGL pipeline) to produce 1) a gas stream comprising predominantly ethane for sales or injection back in the Y-Grade pipeline, 2) a NGL solvent stream comprising predominantly propane (C3) and butane (C4) that may be used in cyclic miscible enhanced oil recovery processes, and 3) a stabilized crude oil stream comprising 90% or greater by mole % of pentane plus (C5+) for stabilized crude oil sales. The pressure of the incoming Y-Grade supply may be about 400 psi to about 600 psi or greater. The mole % of ethane in the incoming Y-Grade may be about 30% or greater as shown in Table 2 for a typical NGL pipeline composition.

[0128] A sixth example of the present system may be operable to process a Y-Grade input stream obtained from a midstream Y-Grade pipeline (NGL pipeline) and trucked Y-Grade from a storage farm. The Y-Grade obtained from both sources may be mixed and processed by the stabilization system to produce 1) a gas stream comprising predominantly ethane for sales or injection back into the Y-Grade pipeline, 2) an NGL solvent stream comprising predominantly propane (C3) and butane (C4) that may be used in cyclic miscible enhanced oil recovery processes, and 3) a stabilized crude oil stream comprising 90% or greater by mole % of pentane plus (C5+) for stabilized crude oil sales. The pressure of the incoming Y-Grade supply may be about 150 psi to about 600 psi or greater depending on the blending ratio of the two sources of Y-Grade in the input stream. The mole % of ethane in the incoming Y-Grade may be about 20% or greater as shown in Table 2 for a typical NGL pipeline composition.

[0129] A seventh example of the present system may include the injection of the propane and butane (C3 and C4) NGL solvent stream produced by the stabilization system into any type of reservoir for carbon sequestration and / or EOR to supplement conventional waterflooding or steam injection methods. In this embodiment the presently disclosed system may be incorporated into the surface equipment of the well processing facility to allow for effective separation and stabilization of the oil sales stream and effective capture of the solvent for reinjection.6. Illustrative Aspects of the InventionAspect 1. A system for stabilizing and separating Y-grade natural gas liquids (NGL), comprising: an input stream comprising unfractionated NGL; a stabilization system comprising: a stabilization column comprising a packing material packed within the stabilization column, wherein an NGL solvent stream is separated from the input stream as the input stream descends through the packing material to produce a stabilized crude oil stream at a base of the stabilization column; a recycle loop comprising a heater, wherein the recycle loop measures a reid vapor pressure (RVP) of the stabilized crude oil stream and recycles the stabilized crude oil stream into the stabilization column if the reid vapor pressure (RVP) of the stabilized crude oil stream falls outside a predetermined range, wherein the stabilized crude oil stream is heated by the heater prior to being recycled into the stabilization column; and a reflux loop operable to recycle a portion of the NGL solvent stream into the stabilization column to offset deviations in mass flowrate of the stabilization system.

[0131] Aspect 2. The system of Aspect 1, wherein the system is installed onsite or near a gas conditioning plant, wherein the input stream comprises unfractionated Y-Grade from the gas conditioning plant, and wherein the NGL solvent stream is injected into a well for enhanced oil recovery.

[0132] Aspect 3. The system of Aspect 1, wherein the NGL solvent stream comprises at least one of methane, ethane, propane, and butane.

[0133] Aspect 4. The system of Aspect 1, further comprising a control system, wherein the control system is operable to adjust a temperature and a pressure of the stabilization column to a second temperature and a second pressure when the measured RVP falls outside the predetermined range to obtain an RVP of the stabilized crude oil stream within the predetermined range.

[0134] Aspect 5. The system of Aspect 1, wherein the stabilization system has a temperature of about 100° F. to about 800° F. and a pressure of about 100 psig to about 600 psig.

[0135] Aspect 6. The system of Aspect 4, wherein the control system is operable to recycle a portion of the NGL solvent stream into the stabilization column upon detecting a buildup of paraffin and asphaltene buildup in the stabilizer column and the heater.

[0136] Aspect 7. The system of Aspect 1, wherein the heated crude oil stream is recycled into the stabilization column at the base of the stabilization column.

[0137] Aspect 8. The system of Aspect 1, wherein the stabilized crude oil stream comprises hydrocarbons with a molecular weight equal to or greater than propane.

[0138] Aspect 9. The system of Aspect 1, wherein the NGL solvent stream exits at a top of the stabilization column as a gas.

[0139] Aspect 10. The system of Aspect 9, wherein the stabilization system further comprises a condenser system, comprising: a compressor operable to compress the gaseous NGL solvent stream; and a cooler operable to condense the compressed gaseous NGL solvent stream to produce a condensed NGL solvent stream comprising predominantly propane and butane.

[0140] Aspect 11. The system of Aspect 1, wherein the unfractionated NGL of the input stream is supplied by a truck, a pipeline, directly from a gas conditioning plant, or a combination thereof.

[0141] Aspect 12. The system of Aspect 10, wherein the condenser system is operable to separate gaseous methane and ethane from the condensed NGL solvent stream.

[0142] Aspect 13. The system of Aspect 1, further comprising an ambient cooler operable to subcool the stabilized crude oil stream prior to storage.

[0143] Aspect 14. The system of Aspect 13, wherein the recycle loop is further operable to recycle a portion of the cooled stabilized crude oil stream to the top of the stabilizer column if the RVP of the stabilized crude oil stream falls outside of the predetermined range.

[0144] Aspect 15. The system of Aspect 4, wherein the second temperature and second pressure are determined using a machine learning and AI algorithm.

[0145] Aspect 16. The system of Aspect 1, further comprising: a well fluid stream extracted from a production well wherein NGL solvent has been injected into the production well; and a three-phase separator operable to separate the well fluid stream into a wet gas stream, a volatile oil stream, and a water stream, wherein the volatile oil stream is fed to the top of the stabilization column separately from the input stream.

[0146] Aspect 17. The system of Aspect 16, further comprising a second condenser system in fluid communication with the three-phase separator, wherein the condenser system is operable to condense ethane, propane, and butane from the wet gas stream to produce a gaseous methane stream and a second NGL solvent stream, wherein the second NGL solvent stream is fed to the condensed NGL solvent storage tank.

[0147] Aspect 18. The system of Aspect 1, further comprising a storage tank in fluid communication with and upstream from the stabilization column, wherein the storage tank is operable to store the unfractionated NGLs of the input stream.

[0148] Aspect 19. The system of Aspect 18, wherein the stabilization system further comprises a pump in fluid communication with the storage tank, wherein the pump is operable to increase the pressure of the stabilization column.

[0149] Aspect 20. The system of Aspect 1, further comprising a second pump operable to increase a pressure of the volatile oil stream prior to feeding the volatile oil stream to the top of the stabilization column.

[0150] Aspect 21. A method of processing unfractionated Y-Grade natural gas liquids (NGLs), comprising: feeding an input stream comprising unfractionated NGLs to a stabilization column,; separating, using the stabilization column, hydrocarbons having a molecular weight less than or equal to pentane from the input stream to produce a gaseous NGL solvent stream and a crude oil stream; stabilizing, using the stabilization system, the crude oil stream to produce a stabilized crude oil stream measuring a reid vapor pressure (RVP) of the stabilized crude oil stream; determining if the RVP of the stabilized crude oil stream falls outside of a predetermined range; and if the RVP falls outside of the predetermined range, heating and recycling the stabilized crude oil stream into the stabilization column.

[0151] Aspect 22. The method of Aspect 21, wherein the stabilized crude oil stream is heated using a heater in fluid communication with the stabilization column.

[0152] Aspect 23. The method of Aspect 21, further comprising determining, using a control system, a required temperature and a required pressure of the stabilization column to obtain a RVP within the predetermined range for the recycled stabilized crude oil stream; and adjusting, using the control system, the stabilization column to operate at the required temperature and required pressure.

[0153] Aspect 24. The method of Aspect 21, wherein the stabilization system has a temperature of about 100° F. to about 800° F. and a pressure of about 100 psig to about 600 psig.

[0154] Aspect 25. The method of Aspect 21, wherein the input stream is fed to the stabilization column using a pump, wherein the pump is operable to increase a pressure of the input stream.

[0155] Aspect 26. The method of Aspect 21, wherein the heated recycled stabilized crude oil stream is fed into the stabilization column at a bottom of the stabilization column.

[0156] Aspect 27. The method of Aspect 21, wherein the stabilized crude oil stream comprises hydrocarbons having a molecular weight equal to or greater than propane.

[0157] Aspect 28. The method of Aspect 21, wherein the unfractionated NGL of the input stream is supplied by f a truck, a pipeline, directly from a production well, or a combination thereof.

[0158] Aspect 29. The method of Aspect 28, further comprising: compressing, using a compressor, the gaseous NGL solvent stream; and condensing, using a cooler, the compressed gaseous NGL solvent stream to produce a condensed NGL solvent stream.

[0159] Aspect 30. The method of Aspect 29, further comprising feeding the condensed NGL solvent stream to an NGL solvent storage tank.

[0160] Aspect 31. The method of Aspect 29, further comprising injecting the condensed NGL solvent stream into a production well(s) for enhanced oil recovery.

[0161] Aspect 32. The method of Aspect 29, wherein a methane content of the compressed gaseous NGL remains gaseous, the method further comprising separating the gaseous methane content from the condensed NGL solvent stream.

[0162] Aspect 33. The method of Aspect 21, further comprising cooling the stabilized crude oil stream using an ambient cooler and storing the cooled stabilized crude oil stream at an oil storage tank.

[0163] Aspect 34. The method of Aspect 33, further comprising recycling a portion of the cooled stabilized crude oil stream to the top of the stabilization column if the RVP of the stabilized crude oil stream falls outside of the predetermined range.

[0164] Aspect 35. The method of Aspect 23, wherein the control system determines the required temperature and the required pressure using a machine learning and AI algorithm.

[0165] Aspect 36. The method of Aspect 21, further comprising: feeding a well fluid stream extracted from a production well to a three-phase separator, wherein NGL solvent has been injected into the production well; separating, using the three-phase separator, the well fluid stream into a wet gas stream, a volatile oil stream, and a water stream; and feeding the volatile oil stream to the top of the stabilization column separately from the input stream.

[0166] Aspect 37. The method of Aspect 36, further comprising: compressing, using a second compressor, the wet gas stream; condensing, using a second cooler, the compressed wet gas stream to produce a gaseous methane stream and a second NGL solvent stream; and feeding the second NGL solvent stream into the NGL solvent storage tank.

[0167] Aspect 38. The method of Aspect 21, further comprising: detecting, by the control system, a buildup of paraffin or asphaltene in the stabilizer column and the heater; and recycling a portion of the NGL solvent stream to the top of the stabilization column.

[0168] Aspect 39. The method of Aspect 38, further comprising increasing a pressure of the stabilization column using a pump in fluid communication with the input stream.

[0169] Aspect 40. The method of Aspect 21, wherein the stabilization column comprises a packing material packed within the stabilization column wherein the packing material comprises stainless steel alloys, carbon steel alloys, aluminum alloys, ceramics, or a combination thereof.

Claims

1. A system for stabilizing and separating Y-grade natural gas liquids (NGL), comprising:an input stream comprising unfractionated NGL;a stabilization system comprising:a stabilization column comprising a packing material packed within the stabilization column, wherein an NGL solvent stream is separated from the input stream as the input stream descends through the packing material to produce a stabilized crude oil stream at a base of the stabilization column;a recycle loop comprising a heater, wherein the recycle loop measures a reid vapor pressure (RVP) of the stabilized crude oil stream and recycles the stabilized crude oil stream into the stabilization column if the reid vapor pressure (RVP) of the stabilized crude oil stream falls outside a predetermined range, wherein the stabilized crude oil stream is heated by the heater prior to being recycled into the stabilization column; anda reflux loop operable to recycle a portion of the NGL solvent stream into the stabilization column to offset deviations in mass flowrate of the stabilization system.

2. The system of claim 1, wherein the system is installed onsite or near a gas conditioning plant, wherein the input stream comprises unfractionated Y-Grade from the gas conditioning plant, and wherein the NGL solvent stream is injected into a well for enhanced oil recovery.

3. The system of claim 1, wherein the NGL solvent stream comprises at least one of methane, ethane, propane, and butane.

4. The system of claim 1, further comprising a control system, wherein the control system is operable to adjust a temperature and a pressure of the stabilization column to a second temperature and a second pressure when the measured RVP falls outside the predetermined range to obtain an RVP of the stabilized crude oil stream within the predetermined range.

5. The system of claim 1, wherein the stabilization system has a temperature of about 100° F. to about 800° F. and a pressure of about 100 psig to about 600 psig.

6. The system of claim 4, wherein the control system is operable to recycle a portion of the NGL solvent stream into the stabilization column upon detecting a buildup of paraffin and asphaltene buildup in the stabilizer column and the heater.

7. The system of claim 1, wherein the heated crude oil stream is recycled into the stabilization column at the base of the stabilization column.

8. The system of claim 1, wherein the stabilized crude oil stream comprises hydrocarbons with a molecular weight equal to or greater than propane.

9. The system of claim 1, wherein the NGL solvent stream exits at a top of the stabilization column as a gas, and wherein the stabilization system further comprises a condenser system, comprising:a compressor operable to compress the gaseous NGL solvent stream; anda cooler operable to condense the compressed gaseous NGL solvent stream to produce a condensed NGL solvent stream comprising predominantly propane and butane.

10. The system of claim 1, wherein the unfractionated NGL of the input stream is supplied by a truck, a pipeline, directly from a gas conditioning plant, or a combination thereof, and wherein the condenser system is operable to separate gaseous methane and ethane from the condensed NGL solvent stream.

11. The system of claim 1, further comprising an ambient cooler operable to subcool the stabilized crude oil stream prior to storage, and wherein the recycle loop is further operable to recycle a portion of the cooled stabilized crude oil stream to the top of the stabilizer column if the RVP of the stabilized crude oil stream falls outside of the predetermined range.

12. The system of claim 4, wherein the second temperature and second pressure are determined using a machine learning and AI algorithm.

13. The system of claim 1, further comprising:a well fluid stream extracted from a production well wherein NGL solvent has been injected into the production well; anda three-phase separator operable to separate the well fluid stream into a wet gas stream, a volatile oil stream, and a water stream,wherein the volatile oil stream is fed to the top of the stabilization column separately from the input stream;a second condenser system in fluid communication with the three-phase separator, wherein the condenser system is operable to condense ethane, propane, and butane from the wet gas stream to produce a gaseous methane stream and a second NGL solvent stream, wherein the second NGL solvent stream is fed to the condensed NGL solvent storage tank.

14. The system of claim 1, further comprising a storage tank in fluid communication with and upstream from the stabilization column, wherein the storage tank is operable to store the unfractionated NGLs of the input stream, wherein the stabilization system further comprises a pump in fluid communication with the storage tank, wherein the pump is operable to increase the pressure of the stabilization column.

15. The system of claim 1, further comprising a second pump operable to increase a pressure of the volatile oil stream prior to feeding the volatile oil stream to the top of the stabilization column.

16. A method of processing unfractionated Y-Grade natural gas liquids (NGLs), comprising:feeding an input stream comprising unfractionated NGLs to a stabilization column;separating, using the stabilization column, hydrocarbons having a molecular weight less than or equal to pentane from the input stream to produce a gaseous NGL solvent stream and a crude oil stream;stabilizing, using the stabilization system, the crude oil stream to produce a stabilized crude oil streammeasuring a reid vapor pressure (RVP) of the stabilized crude oil stream;determining if the RVP of the stabilized crude oil stream falls outside of a predetermined range; andif the RVP falls outside of the predetermined range, heating and recycling the stabilized crude oil stream into the stabilization column.

17. The method of claim 16, wherein the stabilized crude oil stream is heated using a heater in fluid communication with the stabilization column.

18. The method of claim 17, further comprisingdetermining, using a control system, a required temperature and a required pressure of the stabilization column to obtain a RVP within the predetermined range for the recycled stabilized crude oil stream; andadjusting, using the control system, the stabilization column to operate at the required temperature and required pressure.

19. The method of claim 16, wherein the stabilization system has a temperature of about 100° F. to about 800° F. and a pressure of about 100 psig to about 600 psig.

20. The method of claim 16, wherein the input stream is fed to the stabilization column using a pump, wherein the pump is operable to increase a pressure of the input stream.

21. The method of claim 16, wherein the stabilized crude oil stream comprises hydrocarbons having a molecular weight equal to or greater than propane.

22. The method of claim 16, wherein the unfractionated NGL of the input stream is supplied by a truck, a pipeline, directly from a production well, or a combination thereof, the method further comprising:compressing, using a compressor, the gaseous NGL solvent stream; andcondensing, using a cooler, the compressed gaseous NGL solvent stream to produce a condensed NGL solvent stream.

23. The method of claim 22, further comprising feeding the condensed NGL solvent stream to an NGL solvent storage tank.

24. The method of claim 22, further comprising injecting the condensed NGL solvent stream into a production well(s) for enhanced oil recovery.

25. The method of claim 22, wherein a methane content of the compressed gaseous NGL remains gaseous, the method further comprising separating the gaseous methane content from the condensed NGL solvent stream.

26. The method of claim 16, further comprising:cooling the stabilized crude oil stream using an ambient cooler and storing the cooled stabilized crude oil stream at an oil storage tank; andrecycling a portion of the cooled stabilized crude oil stream to the top of the stabilization column if the RVP of the stabilized crude oil stream falls outside of the predetermined range.

27. The method of claim 16, further comprising:feeding a well fluid stream extracted from a production well to a three-phase separator, wherein NGL solvent has been injected into the production well;separating, using the three-phase separator, the well fluid stream into a wet gas stream, a volatile oil stream, and a water stream; andfeeding the volatile oil stream to the top of the stabilization column separately from the input stream.

28. The method of claim 27, further comprising:compressing, using a second compressor, the wet gas stream;condensing, using a second cooler, the compressed wet gas stream to produce a gaseous methane stream and a second NGL solvent stream; andfeeding the second NGL solvent stream into the NGL solvent storage tank.

29. The method of claim 16, further comprising:detecting, by the control system, a buildup of paraffin or asphaltene in the stabilizer column and the heater; andrecycling a portion of the NGL solvent stream to the top of the stabilization column.

30. The method of claim 29, further comprising:increasing a pressure of the stabilization column using a pump in fluid communication with the input stream, wherein the stabilization column comprises a packing material packed within the stabilization column wherein the packing material comprises stainless steel alloys, carbon steel alloys, aluminum alloys, ceramics, or a combination thereof.

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