Patent Application
20250051670
Embodiments of the disclosure generally relate to methane and greenhouse gas abatement systems and methods.
CO2 and methane gas (CH4) make up a significant portion of greenhouse gases which are known for causing global warming. Other types of greenhouse gases include butane gas and other gases. The Paris Agreement commits signatory countries to work towards the goal of limiting global temperature increases to well below 2 degrees Celsius by the end of the century, while pursuing efforts to limit the increase to 1.5 degrees Celsius.
CO2 remains in the atmosphere over a long period of time. It slowly dissolves in the oceans and contributes to their acidification. It is estimated that between 30% and 50% of all the CO2 emitted by anthropogenic emissions have been trapped by the oceans.
The combustion of fossil energy (coal, oil, and gas) in transportation, electricity generation, heavy industry, and housing, are the main sources of CO2 released into the atmosphere. Global atmospheric CO2 was recorded to be 409.8±0.1 ppm in 2019, a new record high. That is an increase of 2.5±0.1 ppm from 2018, similar to the increase between 2017 and 2018.
Capturing CO2 at the source of large electricity generation and heavy industry sites for storage, constitutes, on a global scale, one of the most advanced research pathways for meeting global warming targets.
Regarding the existing approaches for dealing with associated gas as a product of oil extraction activities where no economic means of monetizing are available, the following routes are available:
A first route is to vent the gas produced in the extraction of oil. This approach emits methane and CO2 in direct proportion to the volumes produced. This approach is seen as the worst possible disposition of the gas and allowed only during emergencies and not as part of usual course of business.
The venting of raw natural gas may emit in addition to CO2 and CH4 other contaminants such as hydrogen sulfide (H2S) and heavier hydrocarbons. Venting of production gas is considered the worst option to deal with the produced gas.
A second possible alternative is flaring, with combustion of methane and other hydrocarbon gases in the associated gas stream being reduced to mostly CO2 and water. However, such combustion also generates marginal production of nitrogen and sulfur oxides (NOx & SOx respectively) from elimination of other contaminants present in the stream. Flaring does not eliminate all methane but estimated to close to 98% under field conditions5. As an example, a 100-ton methane discharge to the flare equates to 174 CO2e tons emitted to the environment using the CH4 20-year GWP. Although, heavily regulated at the State and Federal levels, flaring is a commonplace practice in the Oil and Gas industry.
Another method of the prior art is to eliminate methane production by shutting in the oil production altogether. This option has become commonplace considering the current social and environmental pressures operators are experiencing lately. Oil companies often choose not to produce from wells that are not tied into pipelines that can economically move the produced gas for further processing and avoid venting or flaring such production. Even though this approach may appear to meet the needs for emissions curbing for wells, it also results in new wells being drilled to meet the energy demand, with such wells also generating their share of green house gas emissions. The construction of some of these new wells could be offset if providing a viable solution to maintain production from current mature wells drilled many years ago. An additional downside of mothballing wells is that leaks of methane from these inactive facilities may occur and require additional resources for their maintenance.
Methane, however, has been proven to be a much more powerful and detrimental agent than CO2 in terms of contributing to global warming and is responsible for approximately one-third of the resulting climate disruption. Addressing methane is both urgent and essential to mitigate climate change, support environmentally sustainable ambitions of all stakeholders.
The reduction of methane release is a very important part of managing the global warming puzzle, particularly in the near term. It is also a key point in meeting Paris Agreement goals and the objectives of major oil & gas industry participants large and small alike. The reduction in methane emissions, due to its documented shorter life and greater warming potential, can potentially have a greater effect on the global temperature trajectory over all other initiatives collectively.
It is a common problem in the prior art that oil and gas companies struggle with what to do when they accidentally hit natural gas formations while drilling for oil. Whereas oil can easily be trucked out to from a remote destination without proper surface production facilities, gas delivery usually requires a pipeline. If well sites are in the vicinity of a pipeline, the production gas can be transferred to the pipeline effectively but, if the well site is remotely located from a pipeline, transfers are more complicated. It is important to highlight that the recorded estimated figures in TCF of remote, mature, low-pressure fields and well sites in the United States categorized as Flared Associated Gas is 5-10 TCF and Stranded Due to Distance to Market is 270 TCF per the U.S. Department of Energy.
Very frequently, low pressure wells and their maturing production are not big enough to warrant the time and expense of building an entirely new pipeline network or even a connection to the closest existing pipeline facility. If drillers or field owners/producers cannot immediately find a way to dispose of the volumes of natural gas produced, most look to do so on site through different methods.
As disclosed herein above, venting is one option, which releases methane directly into the air which is harmful for the environment, as its greenhouse effects are shown to be much stronger than carbon dioxide in terms of damaging intensity. A more environmentally friendly and many times permissible option is to flare the production gas, which means the combustion of such gas. Nonetheless, flares are only 75% to 90% efficient leading to some of the initial methane being vented without being combusted causing additional problems for the production streams, as well as the resulting carbon dioxide emissions associated to the combustion.
What is needed are methods and systems for methane abatement that re-route, recover and process gas for storage at a well site.
Some implementations herein relate to a system. For example, an gas upcycle system may include a feed gas source configured to supply a feed gas. The gas upcycle system may also include a gas processing system module coupled to the feed gas source. The system may furthermore include a compression and power management module coupled to the gas processing system module. The system may in addition include a storage and treatment module coupled to the gas processing system module and the compression and power management module. The system may moreover include a safety and control systems module. Other embodiments of this aspect include corresponding computer systems, apparatus, and computer programs recorded on one or more computer storage devices, each configured to perform the actions of the methods.
The described implementations may also include one or more of the following features. The gas upcycle system where the gas processing system module is configured to remove a plurality of condensates and contaminants from the feed gas and to transfer the plurality of condensates and contaminants to the storage and treatment module and where the gas processing system module is configured to produce a processed gas stream and is further configured to transfer the processed gas stream to the compression and power management module. The gas upcycle system where the gas processing system module may include any of a separator unit, an hydrogen sulfide removal unit, a carbon dioxide removal unit and a water removal unit configured to remove the plurality of condensates and contaminants from the feed gas. The gas upcycle system where the hydrogen sulfide removal unit may include an iron sponge. The gas upcycle system where the carbon dioxide removal unit may include a molecular sieve. The gas upcycle system where the gas processing system module further may include a filter. The gas upcycle system where the feed gas includes an acid and where the gas processing system module is configured to sweeten the feed gas. The gas upcycle system where the gas processing system module is configured to sweeten the feed gas using any of a batch process, amines, oxidation, molecular sieves, physical solvents, potassium carbonate and membranes. The gas upcycle system where the compression and power management module may include of at least one compressor unit configured to receive the processed gas and the at least one compressor unit is further configured to remove a liquid from the processed gas and to produce a compressed processed gas. The gas upcycle system where the compression and power management module is configured to deliver the liquid and the compressed processed gas to the storage and treatment module. The gas upcycle system where the storage and treatment module may include of a compressed gas storage unit configured to receive the compressed processed gas and a condensates storage unit configured to receive the liquid. The gas upcycle system where the storage and treatment module is further may include of a chemical injection unit coupled to any of the compressed gas storage unit and the condensates storage unit.
The gas upcycle system where the storage and chemical treatment system module is configured to remove a plurality of contaminants from the compressed processed gas. The gas upcycle system where the storage and chemical treatment system module further may include a storage tank, a pipeline and a tanker. The gas upcycle system where the safety and control systems module may include of any of an electrical generator unit, an electrical substation unit and a safety and control unit. The gas upcycle system where the electrical generator unit is configured to receive the compressed processed gas and to generate electrical power and to deliver the electrical power to any of the gas processing system module, the compression and power management module, the storage and treatment module and the safety and control systems module. The gas upcycle system where the electrical substation unit is configured to receive electrical power from an external power source and to deliver the electrical power to any of the gas processing system module, the compression and power management module, the storage and treatment module and the safety and control systems module. The gas upcycle system where the safety and control unit is configured to control any of the electrical generator unit and the electrical substation unit. The gas upcycle system where the compressed processed gas may include a commercial grade natural gas. The gas upcycle system where the compression and power management module may include of a multi-stage compressor unit may include of a plurality of compressors configured to progressively boost a pressure of the compressed processed gas to a final pressure. The gas upcycle system may include a plurality of cooling units coupled to a respective one of the plurality of compressors. The gas upcycle system where the feed gas source is any of a production gas flow, a waste gas flow and a fugitive emission flow. The gas upcycle system where the feed gas source is from any of an oil production facility, a gas production facility, a pipeline, a chemical process, a manufacturing process and an industrial process. The gas upcycle system where the feed gas from the feed gas source may include a green house gas. The gas upcycle system where feed gas may include of any of a methane gas and and a butane gas. Implementations of the described techniques may include hardware, a method or process, or a computer tangible medium.
Some implementations herein relate to a mobile system. For example, the mobile gas upcycle system may include a feed gas source configured to supply a feed gas. The mobile gas upcycle system may also include a motorized vehicle having a truck, a trailer coupled to the truck, a gas processing system module positioned on the trailer coupled to the feed gas source, a compression and power management module positioned on the trailer coupled to the gas processing system module, a storage and treatment module coupled to the gas processing system module and the compression and power management module and at least partially positioned on the trailer, and a safety and control systems module at least partially positioned on the trailer. Other embodiments of this aspect include corresponding computer systems, apparatus, and computer programs recorded on one or more computer storage devices, each configured to perform the actions of the methods.
The described implementations may also include one or more of the following features. The mobile gas upcycle system where the gas processing system module is configured to remove a plurality of condensates and contaminants from the feed gas and to transfer the plurality of condensates and contaminants to the storage and treatment module and where the gas processing system module is configured to produce a processed gas stream and is further configured to transfer the processed gas stream to the compression and power management module. The mobile gas upcycle system where the gas processing system module may include any of a separator unit, an hydrogen sulfide removal unit, a carbon dioxide removal unit and a water removal unit configured to remove the plurality of condensates and contaminants from the feed gas. The mobile gas upcycle system where the hydrogen sulfide removal unit may include an iron sponge. The mobile gas upcycle system where the carbon dioxide removal unit may include a molecular sieve. The mobile gas upcycle system where the gas processing system module further may include a filter. The mobile gas upcycle system where the feed gas includes an acid and where the gas processing system module is configured to sweeten the feed gas. The mobile gas upcycle system where the gas processing system module is configured to sweeten the feed gas using any of a batch process, amines, oxidation, molecular sieves, physical solvents, potassium carbonate and membranes. The mobile gas upcycle system where the compression and power management module may include of at least one compressor unit configured to receive the processed gas and the at least one compressor unit is further configured to remove a liquid from the processed gas and to produce a compressed processed gas. The mobile gas upcycle system where the compression and power management module is configured to deliver the liquid and the compressed processed gas to the storage and treatment module. The mobile gas upcycle system where the storage and treatment module may include of a compressed gas storage unit configured to receive the compressed processed gas and a condensates storage unit configured to receive the liquid. The mobile gas upcycle system where the storage and treatment module is further may include of a chemical injection unit coupled to any of the compressed gas storage unit and the condensates storage unit. The mobile gas upcycle system where the storage and chemical treatment system module is configured to remove a plurality of contaminants from the compressed processed gas. The mobile gas upcycle system where the storage and chemical treatment system module further may include a storage tank. The mobile gas upcycle system where the safety and control systems module may include of any of an electrical generator unit, an electrical substation unit and a safety and control unit. The mobile gas upcycle system where the electrical generator unit is configured to receive the compressed processed gas and to generate electrical power and to deliver the electrical power to any of the gas processing system module, the compression and power management module, the storage and treatment module and the safety and control systems module. The mobile gas upcycle system where the electrical substation unit is configured to receive electrical power from an external power source and to deliver the electrical power to any of the gas processing system module, the compression and power management module, the storage and treatment module and the safety and control systems module. The mobile gas upcycle system where the safety and control unit is configured to control any of the electrical generator unit and the electrical substation unit. The mobile gas upcycle system where the compressed processed gas may include a commercial grade natural gas. The mobile gas upcycle system where the truck is powered at least in part by the commercial grade natural gas. The mobile gas upcycle system where the compression and power management module may include of a multi-stage compressor unit may include of a plurality of compressors configured to progressively boost a pressure of the compressed processed gas to a final pressure. The mobile gas upcycle system may include a plurality of cooling units coupled to a respective one of the plurality of compressors. The mobile gas upcycle system where the feed gas source is any of a production gas flow, a waste gas flow and a fugitive emission flow. The mobile gas upcycle system where the feed gas source is from any of an oil production facility, a gas production facility, a pipeline, a chemical process, a manufacturing process and an industrial process. The mobile gas upcycle system where the feed gas from the feed gas source may include a green house gas. The mobile gas upcycle system where feed gas may include of any of a methane gas and a butane gas. Implementations of the described techniques may include hardware, a method or process, or a computer tangible medium.
Some implementations herein relate to a method. For example, the method may include supplying the feed gas from a feed gas source. The method may also include coupling a gas processing system module to the feed gas source. The method may furthermore include coupling a compression and power management module to the gas processing system module. The method may in addition include coupling a storage and treatment module to the gas processing system module and the compression and power management module. The method may moreover include providing a safety and control systems module. Other embodiments of this aspect include corresponding computer systems, apparatus, and computer programs recorded on one or more computer storage devices, each configured to perform the actions of the methods.
The described implementations may also include one or more of the following processes. The method may include removing a plurality of condensates and contaminants from the feed gas, transferring the plurality of condensates and contaminants to the storage and treatment module, producing a processed gas stream, and transferring the processed gas stream to the compression and power management module. The method further including removing the plurality of condensates and contaminants from the feed gas using any of a separator unit, an hydrogen sulfide removal unit, a carbon dioxide removal unit and a water removal unit. The method where the compression and power management module may include of at least one compressor unit, the method may include producing a compressed processed gas using the at least one compressor unit, and removing a liquid from the processed gas. The method further including delivering the liquid and the compressed processed gas to the storage and treatment module. The method may include receiving the compressed processed gas into a compressed gas storage unit within the storage and treatment module and receiving the liquid into a condensates storage unit within the storage and treatment module. The method may include injecting at least one chemical into any of the compressed gas storage unit and the condensates storage unit. The method where the safety and control systems module may include of any of an electrical generator unit, an electrical substation unit and a safety and control unit. The method where the compressed processed gas may include a commercial grade natural gas. The method where the compression and power management module may include of a multi-stage compressor unit may include of a plurality of compressors, the method may include boosting a pressure of the compressed processed gas to a final pressure. The method may include coupling a plurality of cooling units to a respective one of the plurality of compressors. The method where the feed gas source is any of a production gas flow, a waste gas flow and a fugitive emission flow. The method where the feed gas source is from any of an oil production facility, a gas production facility, a pipeline, a chemical process, a manufacturing process and an industrial process. The method where the feed gas from the feed gas source may include a green house gas. The method where feed gas may include of any of a methane gas and a butane gas. Implementations of the described techniques may include hardware, a method or process, or a computer tangible medium.
So that the manner in which the above-recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized above, can be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments.
In the following detailed description of the embodiments, reference is made to the accompanying drawings, which form a part hereof, and within which are shown by way of illustration specific embodiments by which the examples described herein can be practiced. It is to be understood that other embodiments can be utilized and structural changes can be made without departing from the scope of the disclosure.
One subject of the present systems and methods that process, condition, compress and store natural gas from oil production activities is to repurpose production gas flow and waste gas flows such as those described above away from normalized combustion or venting applications as well as other fugitive emission flow.
The systems and methods disclosed herein are particularly suitable for the recovery and repurposing of a gas feed source of an oil production facility as well as other fugitive emission sources with a view for processing and storage wasted gases to comply with high quality standards and conditions. Typically, associated gas produced during oil extraction will be combusted or vented. Flaring is long known as a wasteful practice that releases CO2 and hazardous air pollution components; experience also suggests that flaring, can also be a major methane source either by becoming unlit and release unabated natural gas into the atmosphere, or by unwanted and incomplete combustion events. Fugitive emissions are leaks and other irregular releases of gases or vapors from a pressurized containment-such as appliances, storage tanks, pipelines, wells, or other pieces of equipment-mostly associated with oil and gas extraction, transport and refining activities. In addition to the economic cost of lost commodities, fugitive emissions contribute to local air pollution and may cause further environmental harm. It should be further noted that the systems and methods disclosed herein are suitable for use with on-shore wells, off shore wells, risers, production stacks and flares. In addition, systems and methods of the present disclosure is equally suitable for other applications such as industrial process applications including power plants, cement plants, gas plants, manufacturing process plants, petrochemical plants and the like.
Components of the gas stream or of its resulting combustion such as hydrogen sulfide (H2S) water or Carbon dioxide (CO2) can be removed from the produced gas with a view to upgrade it to commercial quality and make the resulting grades of quality acceptable to pipeline transportation or commercial fuel standards using implementations disclosed herein. Such commercial quality gases can include commercial grade natural gas.
The systems and methods disclosed herein be used to unlock sequestered deposits of natural gas efficiently, productively, and economically with the urgency required for a large swath of the oil and gas production landscape. Implementations are disclosed that can intake a stream of produced or manufactured gas from a gas production facility that add value to this intake stream and contribute to a net zero outcome while substantially reducing methane emissions by repurposing gas flows. Implementations are disclosed that can handle a larger range of both chemical and physical conditions found in different production gases facilities. Also disclosed are systems that are modular and scalable and can be used on a wide range of produced gas compositions (leaner to richer gas in more environments and production scenarios) and a wide range of field production conditions with varying pressures and temperatures. The modular and scalable systems disclosed herein can range from small-sized to fit on a truck (
In accordance with the foregoing objectives and others, the following disclosure is made herein to outline exemplary systems and methods that processes, conditions, compresses and stores natural gas from oil production activities to repurposing gas flows away from normalized combustion or venting applications.
Referring to
Now with reference to
Next with reference to
Next with reference to
Safety, control and utilities system module 4000 further comprises both all the safety and control systems of the methods and systems proposed as well as the utilities supporting its operation.
The methods and systems disclosed herein can be self-sufficient for operation purposes, and as such, UWA 20 can be configured to generate is own power.
Alternatively, power external to UWA 20 can be sourced from the local grid. Referring now to
To ensure the safe and reliable operation of the methods and systems of safety, control and utilities system module 4000 includes safety and control unit 4300 which comprises the requisite safety and controls managements systems and houses the requirements for localized intervention for operation and control including processors, computer storage, communications, software and associated systems. safety and control unit 4300 is further configured to control the operational intervention procedures which may be required at the location of UWA 20. Also included in safety and control unit 4300, is the network capability to transmit and receive selected information from an external source (such as third party systems module 5000,
Third party systems module 5000 is configured to be adapted for the requirements of third parties related to the operation of UWA 20 and includes the configurations required to accomplish operational and controls tasks remotely Such configurations can include wireless and Wi-Fi enable devices and applications.
The operation of UWA 20 can be conceptualized as process, activities, function sections and operational areas. As an example, and with reference to
Similarly, the functional sections comprise:
Further, the operational areas comprise:
It should be appreciated by those skilled in the art that the systems and methods disclosed herein enable the repurposing and processing of gases destined to be flared or vented as part of prior art production operation practices. As disclosed herein above, the methods and systems are comprised of multiple modules and sequencing of conditioning elements where the result is a revalued variety of gas products for offtake to market. Products result from conversion of flows through the sequence of methods and systems that offset methane and other green house gas emissions and permit re-classification of gas reserves previously understood to be unusable but recoverable in nature.
As disclosed herein above, after UWA 20 is coupled to the outlet of a wellhead production facility the process conversion can autonomous wherein the UWA utilizes processed gas from the feed gas source to power the UWA. The work of the methods and systems can be divided into multiple stages, including as noted above in the simplified process activities of
Now referring to
Referring next to
Simulations were run for the UWA 20 disclosed herein above to validate the inventiveness and efficacy of the UWA. Aspen HYSYS (HYSYS) was used as the simulator platform as it is a chemical process simulator currently developed by AspenTech used to mathematically model chemical processes, from unit operations to full chemical plants and refineries. As will be set forth in detail herein below, HYSYS was extremely useful in simulating the UWA 20 of the present disclosure. HYSYS is able to perform many of the core calculations of chemical engineering, including those concerned with mass balance, energy balance, vapor-liquid equilibrium, heat transfer, mass transfer, chemical kinetics, fractionation, and pressure drop. With reference to
As disclosed herein above, simulations were performed using HYSYS for UWA 7000 for the conditions listed in Table 1 for cases 1-5. Table 2 shows the conditions and compositions of the gas stream for final gas output 709 being sent to compressed gas storage unit 3100.
As disclosed herein above, each of the four compression stages of multi-compressor system 708 includes an input power for both the mechanical compressors and the cooling units. The total energy requirements for multi-compressor system 708 for cases 1-5 are shown in Table 3:
Simulation runs shown in Table 2 above have shown the presence of condensate species (C3, C4 & C5+) in the gas stream to storage. Industrial experience shows the presence of such species is lesser in the gas stream to storage, and these components tend to be recovery during the different stages of compression as condensates. Condensate modelling accuracy is a well know phenomenon requiring detailed and additional simulation work to better estimate such occurrence. Additional sensitivities were run utilizing discrete changes to the compression operating conditions (e.g., increase of cooling duty and gas composition of the feed gas). These runs confirmed the condensate recovery.
In addition to the simulations for cases 1-5 summarized directly herein above, process simulation sensitivity analyses were performed for three different inlet natural gas compositions A, B, C. The purpose of process simulation sensitivity analyses is to confirm the likelihood of condensate formation (e.g., liquids) and, therefore, confirm the requirement for equipment, such as condensate storage unit 3200, to handle the recovery of such liquids and their disposal.
The properties of feed gas 701 used in the sensitivity analyses are summarized in Table 4 below.
As disclosed herein above, UWA 700 handling and processing consists of a liquid-gas separator section in separator 702, a gas sweeting (H2S removal) section comprising iron sponge 705, a subsequent water (H2O) and carbon dioxide (CO2) removal section comprising sieve 706, a multi-compressor system 708 with each compression stage comprising a reciprocating compressor, an air cooler and a liquid-gas separator vessel, and compressed gas storage unit 3100 comprising a high-pressure gas storage facility for final gas output 709.
For Case A, feed gas 701 comprises a gas composition having 91.73% of C1-C2 and 4.79% of C3+ compounds, as is shown in Table 4. Processed gas stream 707 is assumed to be dry gas at the inlet to multi-compressor system 708, wherein the H2S, H2O and CO2 have been removed by iron sponge 705 and sieve 706. The composition of final gas output 709 comprises a 94.84% C1-C2 and 4.94% C3+ composition.
The properties and composition of processed gas stream 707 entering multi-compressor system 708 are shows in Table 5.
Compression
.35
0
.50
7
indicates data missing or illegible when filed
Now referring to
For Case B, feed gas 701 comprises a 78.92% C1-C2 and 17.26% C3+ composition, of which 10.16% correspond to propane, as is shown in Table 6. After removal H2S, H2O and CO2, processed gas stream 707 at the inlet to multi-compressor system 708, the processed gas comprises an 80.21% C1-C2 and 17.53% C3+ composition.
The properties and composition of processed gas stream 707 entering multi-compressor system 708 are shows in Table 6.
Compression
.91
indicates data missing or illegible when filed
Referring now to
As can be seen from Table 6, Case B comprises a feed gas 701 having a heavier hydrocarbon composition. The results of the simulation for Case B confirms that the occurrence of a liquid stream is favored by the heavier hydrocarbon presence in feed gas 701. These results are to be expected because the heavier hydrocarbons expand the phase envelope to reach a higher crycondentherm point 101 and a wider pressure range within the dome at lower pressures at the desired operating temperature than in Case A above.
Case C comprises a feed gas 701 which is a relatively leaner gas, with conditions and compositions for the feed gas entering multi-compressor system 708 shown Table 7.
Compression
.91
indicates data missing or illegible when filed
For Case C, feed gas 701 comprises a composition of 89.08% of C1-C2 and 9.12% of C3+ compounds. After removal of H2S, H2O and CO2, the gas mixture of processed gas stream 707 comprises a 90.54% C1-C2 and 9.26% C3+ composition, as is shown in Table 7.
Referring now to
In the first stage of compression multi-compressor system 708, and after the cooling process using the respective cooling units, a small fraction of liquids can obtained, which liquids are comprised mostly of C5-C6 (88.14%). The properties and composition of the liquids from the first stage for Case C are summarized in Table 8 below.
2
0
indicates data missing or illegible when filed
The effect of such liquid exiting the first stage of multi-compressor system 708 can best be seen with reference to
The crycondentherm point 121 at maximum liquid-vapor equilibrium temperature has decreased to 165° F., and the pressure range in the mixed phase zone 122, at the operating temperature 123, is now between about 190 psia and about 2000 psia (horizontal lines 124, 125 respectively). It should be appreciated by those skilled in the art that such conditions allow the liquids extraction to continue in the second stage of compression of multi-compressor system 708, from which a liquids stream with the properties and composition disclosed in the Table 9 can be extracted.
4
4
43
indicates data missing or illegible when filed
As can be appreciated by those skilled in the art, after extraction of the liquid phase following the second stage of compression of multi-compressor system 708, the phase envelope of the mixture will be changed. Such changes can best be seen with reference to
.58
2
0
indicates data missing or illegible when filed
As disclosed herein before, it is advantageous to the condition the feed gas 701 prior to entering multi-compressor system 708 of UWA 700. Several alternatives for ‘sour’ or ‘acid’ natural gas processing (e.g., removal of hydrogen sulfide) are enabled for use with implementations of the UWA disclosed herein and be classified according to the type of application, feed gas 701 properties, requirements, and product specifications. Although many factors are considered in the gas sweetening process selection, (e.g., operating temperature and pressure, environmental and other regulations, available facilities, capital and operating costs) the prior art guide 140 selected as part of the present disclosure shown with reference to
Considering the operating conditions for UWA 700 of the present disclosure wherein the operating conditions of feed gas 701 comprise a typical ‘acid’ content (H2S) is to be below 300 ppm and only traces to none are targeted in final gas output 709, the better options to process the UWA feed gas are those shown in the lower left corner 141 of
Generally, batch processes (b) are usually more economical if the sulfur content of feed gas 701 is known to be below 20 lbs/day. With the UWA gas feed 701 prevalent in many gas wells and can be up to 27 thousands of standard cubic feet per day (kscfd), batch processes are the preferred alternative for the unit design.
Examples of some commercially available batch processes are Chemsweet®, Sulfa-Check® or an iron sponge such as SULFATREAT. Chemsweet® and Sulfa-Check® are sludge processes (operating similar to Amines) and are therefore more complex to use operationally. These batch processes can require additional equipment (e.g. chemical and water storage tanks, mixing equipment, gas-liquid separators, pumps, provide agitation, etc.).
An alternative H2S sweeting process is commonly referred as iron sponge (705,
It should be appreciated by those skilled in the art that there are mainly three types of dehydration processes available for use with implementations of a UWA 700 for feed gas 701 dehydration: 1) absorption by hygroscopic liquids or solids; 2) adsorption by solid desiccants; and 3) condensation by cooling or compression.
Condensation processes are by their very nature energy intensive and require higher investment and costs which are unnecessary and undesirable if from the outset these can be avoided from a technical selection perspective. Typically, absorption represents a higher percentage of operational burden that requires larger equipment footprints such as contact towers, that generate higher operating costs, process and operational complexity among other conditions.
The commercial processes of adsorption by solid desiccants are composed of three (3) types of beds: 1) silica-based adsorbents; 2) alumina-based adsorbents; and 3) molecular sieves. The equipment and process complexity of the processes described tend to be relatively uniform and similar in each case. In many technical cases, adsorbents can be exchanged using the same contact tower and auxiliary equipment generating a desirable condition and convenience for field operations.
Silica and alumina-based beds normally require lower (less) temperature requirements for regeneration. This translates into less dry gas use and lower energy consumption which are favorable conditions. In the case of molecular sieves, favorable conditions include the satisfactory achievements of lower water dewpoints compounded by other desirable conditions whereby carbon dioxide and hydrogen sulfide can be removed simultaneously generation favorable outcomes.
Molecular sieves are fit for purpose and of practical implementation matching the best conditions sought by the current design considerations. Absorption by molecular sieves are the definitive selection for this design that will achieve the removal of carbon dioxide and water most effectively. Further, molecular sieves are undoubtedly the most effective desiccant and adsorbent for drying natural gas for this design. Molecular sieves have high resistance to contamination and their strong crushing properties increase cyclic times that provide an extended product life, all desirable considerations that will permit best possible technical outcomes of the selections. Other favorable competitive advantage of the implementation of molecular sieves is their capability to be regenerated, all the while reducing the overall quantity (amount) required for the design while adding cost benefits that make their inclusion in the design and field operation economically favorable by this study.
The technical recommendation for Adsorption unit consists of at least two (2), potentially vessels filled with molecular sieves that will adsorb both the water and the carbon dioxide in the feed during the process adsorption period and subsequently regeneration using a heated stream of treated gas will occur in satisfactory manner.
It is important to highlight that here are several types of molecular sieves. Referential properties of the most widely used molecular sieves are shown in Table 1 below:
Typically, larger pore sizing equates to higher adsorption capacity. Both, Type 3A and 4A molecular sieves are very frequently utilized for the dehydration of natural gas. Definitively, Type 4A has been selected for this application given that it possesses the ability to absorb water (H2O) and carbon dioxide (CO2) with (a) a consistent adsorption speed, (b) higher degree of stability and (3) demonstrates a higher water retention capability over a Type 3A sieve per unit weight in use. For this reason, the recommendation is to proceed with Type 4A molecular sieves specification for this application as stated above.
A multistage positive displacement compressor is recommended for selection in this application to bring the processed gas to the higher-pressure storage conditions as primary consideration.
For operational purposes, the multistage positive displacement compressor is expected to deliver the flexibility of supplying compressed gas within the range of 2500 up to 4000 psi.
Further, the compressor outlet pressure is expected to offer and provide allowances for the availability of different arrangements to connect to the different gas storage (e.g., Type IV) solutions. Storage would likely vary as per requirements and availability for the disposal route develop across the different commercial scenarios market landscape.
As part of the enablement of the UWA 700 (
Pressure drop calculations for the different components of
For the pressure drop calculations of vessels containing solid loadings, a 1/16″ extruded particle sizing was. The following operating conditions were used: feed gas flow 20% above maximum flow (27 kscfd) and a molecular weight of low methane feed concentration.
It is important to note the unusual smaller sizing and footprint of the UWA vessel services (e.g. sizing, configuration of iron sponge, molecular sieves) result in limited data existing in the prior art for the purposes of comparison and benchmarking of each individual process service (e.g. gas sweetening, molecular sieves). Heretofore there exists no similar arrangement of components, in terms of sizing and process throughput.
The pressure profile across the different vessels is presented in Table 12 below:
Pressure drops for 1″ and 1½″ diameter piping were evaluated at different gas flows rates (e.g., Minimum (10 kscfd), Normal (20 kscfd) and Maximum (30 kscfd) use cases) results are summarized in Table 13 below:
The diameter set to meet the criteria as noted is set under design conditions of is the 1½ inch piping.
With reference to
Through this verification process, the proposed arrangement 150 is confirmed to be both workable and to have sufficient capacity to accommodate requirements for a safe operation at both start of and end of run operating cycles for minimum, normal and maximum gas flow rate process throughputs.
Although the implementations is/are described herein with reference to specific embodiments, various modifications and changes can be made without departing from the scope of the present implementations, as presently set forth in the claims below. Accordingly, the specification and figures are to be regarded in an illustrative rather than a restrictive sense, and all such modifications are intended to be included within the scope of the present implementations. Any benefits, advantages, or solutions to problems that are described herein with regard to specific embodiments are not intended to be construed as a critical, required, or essential feature or element of any or all the claims.
Unless stated otherwise, terms such as “first” and “second” are used to arbitrarily distinguish between the elements such terms describe. Thus, these terms are not necessarily intended to indicate temporal or other prioritization of such elements. The terms “coupled” or “operably coupled” are defined as connected, although not necessarily directly, and not necessarily mechanically. The terms “a” and “an” are defined as one or more unless stated other The terms “comprise” (and any form of comprise, such as “comprises” and “comprising”), “have” (and any form of have, such as “has” and “having”), “include” (and any form of include, such as “includes” and “including”) and “contain” (and any form of contain, such as “contains” and “containing”) are open-ended linking verbs. As a result, a system, device, or apparatus that “comprises,” “has,” “includes” or “contains” one or more elements possesses those one or more elements but is not limited to possessing only those one or more elements. Similarly, a method or process that “comprises,” “has,” “includes” or “contains” one or more operations possesses those one or more operations but is not limited to possessing only those one or more operations.
While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.
This Patent application claims priority to U.S. Provisional Patent Application No. 63/266,198, filed on 30 Dec. 2021, and entitled “METHANE & GREENHOUSE GAS EMISSIONS ABATEMENT SYSTEMS AND METHODS FOR REPURPOSING OF GAS STREAMS EMBEDDED IN OIL PRODUCTION ACTIVITIES. The disclosure of the prior Application is considered part of and is incorporated by reference into this Patent Application.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US22/78954 | 10/31/2022 | WO |
| Number | Date | Country | |
|---|---|---|---|
| 63266198 | Dec 2021 | US |
