G. Giunta, K. Nielsen, G. Bernasconi, L. Bondi, Barry Korubo
Efficiency and safety are primary requirements for oil & gas fluid filled transportation system. However, the complexity of the asset makes it challenging to derive a theoretical framework for managing the control parameters. The current frontier for a real time monitoring exploits the "digital tansformation", i.e. the acquisition and the analysis of large datasets recorded along the whole asset lifecycle, which are used to infer "data driven" relations and to predict the evolution of the asset integrity. This paper presents some results of a research project for the design, implementation and testing of a "machine learning" approach to vibroacoustic data recorded continuously by acquisition units installed every 10-20 km along a pipeline. In a fluid transportation system, vibroacoustic signals are generated by the flow regulation equipment (i.e. pumping, valves, metering), by the fluid flowing (i.e. turbulence, cavitation, bubbles), by third party interference (i.e. spillage, sabotage, illegal tapping), by internal inspection using PIGs operations), and by natural hazards (i.e. microseismic, subsidence, landslides). The basic principle of machine learning is to "observe", for an appropriate time interval, a series of descriptors, in this stage related to vibroacoustic signals but that can be integrated with other physical data (i.e. temperature, density, viscosity), in order to "learn" their safe range of variation or, when properly fed to a classification procedure, to obtain automatically a discrete set of operational status. The classification criteria are then applied to new data, highlighting the presence of system anomalies. The paper considers vibroacoustic signals collected at the flow stations of an oil trunkline in Nigeria. The vibroacoustic signals are the static pressure, the acceleration and the pressure transients recorded at the departure and at the arrival terminals. More than one year of data is available. Derived smart indicators are defined, which are directly linked to the asset parameters: for instance, the cross-correlation of the pressure transients at adjacent measuring locations permits to estimate the fluid channel continuity (correlation value), the sound velocity (time of correlation peak), and the sound attenuation (amplitude versus frequency amplitude decay). A portion of the data during normal operation is used for training and tuning a reference model. After that, new data are compared with the model, and anomalies are automatically detected. Two kind of errors are raised: i) sensors; ii) alerts. Sensor errors are referred to missing or corrupted sensors data. Alerts are raised when the measured physical quantities are not coherent with the functional and known service behaviors of the transport system. The system model is not static over time, and in fact it can be updated by the operators’ feedback, that can tag false alarms and thus, automatically, re-define the set of operational scenarios of the upstream
{"title":"Data Driven Smart Monitoring for Pipeline Integrity Assessment","authors":"G. Giunta, K. Nielsen, G. Bernasconi, L. Bondi, Barry Korubo","doi":"10.2118/197327-ms","DOIUrl":"https://doi.org/10.2118/197327-ms","url":null,"abstract":"\u0000 Efficiency and safety are primary requirements for oil & gas fluid filled transportation system. However, the complexity of the asset makes it challenging to derive a theoretical framework for managing the control parameters. The current frontier for a real time monitoring exploits the \"digital tansformation\", i.e. the acquisition and the analysis of large datasets recorded along the whole asset lifecycle, which are used to infer \"data driven\" relations and to predict the evolution of the asset integrity. This paper presents some results of a research project for the design, implementation and testing of a \"machine learning\" approach to vibroacoustic data recorded continuously by acquisition units installed every 10-20 km along a pipeline.\u0000 In a fluid transportation system, vibroacoustic signals are generated by the flow regulation equipment (i.e. pumping, valves, metering), by the fluid flowing (i.e. turbulence, cavitation, bubbles), by third party interference (i.e. spillage, sabotage, illegal tapping), by internal inspection using PIGs operations), and by natural hazards (i.e. microseismic, subsidence, landslides). The basic principle of machine learning is to \"observe\", for an appropriate time interval, a series of descriptors, in this stage related to vibroacoustic signals but that can be integrated with other physical data (i.e. temperature, density, viscosity), in order to \"learn\" their safe range of variation or, when properly fed to a classification procedure, to obtain automatically a discrete set of operational status. The classification criteria are then applied to new data, highlighting the presence of system anomalies.\u0000 The paper considers vibroacoustic signals collected at the flow stations of an oil trunkline in Nigeria. The vibroacoustic signals are the static pressure, the acceleration and the pressure transients recorded at the departure and at the arrival terminals. More than one year of data is available. Derived smart indicators are defined, which are directly linked to the asset parameters: for instance, the cross-correlation of the pressure transients at adjacent measuring locations permits to estimate the fluid channel continuity (correlation value), the sound velocity (time of correlation peak), and the sound attenuation (amplitude versus frequency amplitude decay). A portion of the data during normal operation is used for training and tuning a reference model. After that, new data are compared with the model, and anomalies are automatically detected. Two kind of errors are raised: i) sensors; ii) alerts. Sensor errors are referred to missing or corrupted sensors data. Alerts are raised when the measured physical quantities are not coherent with the functional and known service behaviors of the transport system.\u0000 The system model is not static over time, and in fact it can be updated by the operators’ feedback, that can tag false alarms and thus, automatically, re-define the set of operational scenarios of the upstream","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87868497","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Dawood Al Mahrouqi, R. Farajzadeh, A. Alkindi, M. Rifaat
Polymer injection in the south of Sultanate of Oman has been implemented in Marmul field for the last decade. Recently, alkaline surfactant polymer (ASP) technology has also been piloted in the field, which was technically successful owing to its significant incremental oil production. The current end-game strategy for the field is to follow polymer with ASP flood in order to produce the remaining oil after polymer flood and maximize the ultimate oil recovery factor. This has revealed the need for evaluation of the full-field performance of ASP flood using available tools. Full-field dynamic models are not always best tools for modeling the performance of chemical enhanced oil recovery, primarily due to under-representation of the reservoir heterogeneity, lack of the complementary data, complexity of the process itself, and large computation time. In this paper, we implement a conduit-model approach using field production data from the ASP pilot to assess the ultimate incremental oil recovery. This approach is compared to an analytical model that is based on the modified Koval's method with reservoir heterogeneity as an input parameter. The obtained results are used for preliminary assessment of the difference between polymer and ASP injection in the full field.
{"title":"Integrated Approach for Analysis and Forecasting of Chemical EOR Recoveries in Sultanate of Oman","authors":"Dawood Al Mahrouqi, R. Farajzadeh, A. Alkindi, M. Rifaat","doi":"10.2118/197840-ms","DOIUrl":"https://doi.org/10.2118/197840-ms","url":null,"abstract":"\u0000 Polymer injection in the south of Sultanate of Oman has been implemented in Marmul field for the last decade. Recently, alkaline surfactant polymer (ASP) technology has also been piloted in the field, which was technically successful owing to its significant incremental oil production. The current end-game strategy for the field is to follow polymer with ASP flood in order to produce the remaining oil after polymer flood and maximize the ultimate oil recovery factor. This has revealed the need for evaluation of the full-field performance of ASP flood using available tools. Full-field dynamic models are not always best tools for modeling the performance of chemical enhanced oil recovery, primarily due to under-representation of the reservoir heterogeneity, lack of the complementary data, complexity of the process itself, and large computation time. In this paper, we implement a conduit-model approach using field production data from the ASP pilot to assess the ultimate incremental oil recovery. This approach is compared to an analytical model that is based on the modified Koval's method with reservoir heterogeneity as an input parameter. The obtained results are used for preliminary assessment of the difference between polymer and ASP injection in the full field.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85899304","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Abdelaziz, S. Masi, A. Shehata, Domenico Cannatelli, C. Cannell
The design of new natural gas liquefaction facilities is closely aligned with the quality of the immediately available feed gas and the SPA’s agreed with customers. However, the lifetime of the facilities often extends beyond the lifetime of both the gas source and the duration of the SPA’s. Recent statistics indicate up to 60 MTPA of global liquefaction capacity is not utilized. Qualitative based approaches are often adopted to assess how an LNG plant responds to a change in feed gas specification. However a more valuable approach uses a quantitative analysis which can achieve an optimal outcome via individual tuning of a potentially large number of plant variables. Such an approach starts by performing actual plant capacity tests for different operating modes and process variables to capture baseline operation performance data. The plant test results are to validate a detailed plant simulation model which includes all the plant variables of interest. The validated model can then help identify the optimum operating condition and the benefits of a range of potential modifications. The methodology was used to identify solutions to a typical problem in a multi-train facility where a change from rich feed stock was accompanied by the presence of aromatics in a significantly leaner feed gas. Detailed modelling of the plant enabled an understanding of the solubility of the aromatics in the lean gas. The previously validated model of the real plant behaviour was then used to evaluate the benefits of changes to the key operating parameters and minor modifications to the plant itself. This resulted in a significantly more efficient and cost-effective solution than simply importing LPG which would have been the solution normally taken by a traditional "qualitative" approach. A similar approach was used to address an associated commercial challenge of satisfying a SPA demanding a high HHV with a leaner feed gas. In this case the solution relied not only on the technical insight afforded by the quantitative analysis but also a recognition that accurate tuning of the operational process allows a reduction in the conservatism of the product specification. Furthermore, with minor modifications, a multi-train process with segregated storage can be operated in multiple HHV mode provided careful procedures are employed to mitigate operational risks. This paper demonstrates how a holistic, detailed, quantitative analysis of gas liquefaction process can provide a good insight into the capability of existing plant to respond to changes in feedstock quality. The outlined methodology combined with a good understanding of the commercial features of the LNG business offers the possibility to better exploit the significant and growing amount of unused gas liquefaction capacity around the world.
{"title":"Challenges to Backfilling an Existing Natural Gas Liquefaction Facility with Different Gas Specifications","authors":"A. Abdelaziz, S. Masi, A. Shehata, Domenico Cannatelli, C. Cannell","doi":"10.2118/197627-ms","DOIUrl":"https://doi.org/10.2118/197627-ms","url":null,"abstract":"\u0000 The design of new natural gas liquefaction facilities is closely aligned with the quality of the immediately available feed gas and the SPA’s agreed with customers. However, the lifetime of the facilities often extends beyond the lifetime of both the gas source and the duration of the SPA’s. Recent statistics indicate up to 60 MTPA of global liquefaction capacity is not utilized.\u0000 Qualitative based approaches are often adopted to assess how an LNG plant responds to a change in feed gas specification. However a more valuable approach uses a quantitative analysis which can achieve an optimal outcome via individual tuning of a potentially large number of plant variables. Such an approach starts by performing actual plant capacity tests for different operating modes and process variables to capture baseline operation performance data. The plant test results are to validate a detailed plant simulation model which includes all the plant variables of interest. The validated model can then help identify the optimum operating condition and the benefits of a range of potential modifications.\u0000 The methodology was used to identify solutions to a typical problem in a multi-train facility where a change from rich feed stock was accompanied by the presence of aromatics in a significantly leaner feed gas. Detailed modelling of the plant enabled an understanding of the solubility of the aromatics in the lean gas. The previously validated model of the real plant behaviour was then used to evaluate the benefits of changes to the key operating parameters and minor modifications to the plant itself. This resulted in a significantly more efficient and cost-effective solution than simply importing LPG which would have been the solution normally taken by a traditional \"qualitative\" approach.\u0000 A similar approach was used to address an associated commercial challenge of satisfying a SPA demanding a high HHV with a leaner feed gas. In this case the solution relied not only on the technical insight afforded by the quantitative analysis but also a recognition that accurate tuning of the operational process allows a reduction in the conservatism of the product specification. Furthermore, with minor modifications, a multi-train process with segregated storage can be operated in multiple HHV mode provided careful procedures are employed to mitigate operational risks.\u0000 This paper demonstrates how a holistic, detailed, quantitative analysis of gas liquefaction process can provide a good insight into the capability of existing plant to respond to changes in feedstock quality. The outlined methodology combined with a good understanding of the commercial features of the LNG business offers the possibility to better exploit the significant and growing amount of unused gas liquefaction capacity around the world.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86862477","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Dalal Al-Subaiei, M. Al-Hamer, Ahmed Al-Zaidan, H. Chetri, Mohammad Sami Nawaz
Global oil demand has led to the development of new smarter drilling, completion, reservoir management technique and technology to optimize reservoirs production. The production of Kuwait Oil Company (KOC) has reached 3 MMBOPD and KOC’s 2030 vision is to boost the production to 4 MMBOPD. In order to achieve this vision, KOC has started several technical projects and development plans. One of these projects is the North Kuwait Integrated Digital Oil Field (NK-KwIDF) a full-fledged Field project implemented in KOC. This Paper will discuss the scale, complexity, technology used, and advantage of using the NK-KwIDF. The North Kuwait (NK) asset has five fields, around twelve hundred active wells, and seven Gathering Centers (GCs). A complex network of pipeline, trunk line, and manifold are used to connect these twelve hundred wells to GCs. In order to optimize the production from NK every barrel of production opportunity has to be considered by optimizing suitable wells and minimizing downtime from each field, resulting the development of an extensive surface network model. The extensive surface network model takes into consideration of each and every details of field e.g. pipelines, manifolds, details of GCs and wells. For each and every well in NK assets a well model is prepared considering all PVT parameters, completions, and surface co-ordinate and finally connected to surface network model with all piping information. Once the extensive surface model was prepared, several integrated workflows were developed in order to efficiently run the surface model and analyze the output from the run. Some of these workflows are ESP Optimization and ESP Analysis workflows, which have capability to identify the Oil Gain Opportunities and diagnose ESP performance. The identify opportunities are logged into ticketing system, which monitors the life cycle of the opportunity right from the identification till implementation into the field for Oil Gains. The full-fledged development of NK-KwIDF took almost 3 years from the day it was started, as a pilot project with 133 wells. When an excellent result in terms of production optimization and downtime minimization was recorded from the pilot project, the pilot project was expanded to full-fledged field project. The NK-KwIDF project gave an outstanding result of Oil gain from well level as well as Network level optimization. It established an excellent reputation in the oil industry where it was a source of attraction for many NOC’s and IOC’s to visit and follow the flag ship for their development and implementation of digital field technology.
{"title":"Intelligent Digital Oilfield Implementation: Production Optimization Using North Kuwait Integrated Digital Oil Field NK KwIDF","authors":"Dalal Al-Subaiei, M. Al-Hamer, Ahmed Al-Zaidan, H. Chetri, Mohammad Sami Nawaz","doi":"10.2118/197811-ms","DOIUrl":"https://doi.org/10.2118/197811-ms","url":null,"abstract":"\u0000 Global oil demand has led to the development of new smarter drilling, completion, reservoir management technique and technology to optimize reservoirs production. The production of Kuwait Oil Company (KOC) has reached 3 MMBOPD and KOC’s 2030 vision is to boost the production to 4 MMBOPD. In order to achieve this vision, KOC has started several technical projects and development plans. One of these projects is the North Kuwait Integrated Digital Oil Field (NK-KwIDF) a full-fledged Field project implemented in KOC.\u0000 This Paper will discuss the scale, complexity, technology used, and advantage of using the NK-KwIDF. The North Kuwait (NK) asset has five fields, around twelve hundred active wells, and seven Gathering Centers (GCs). A complex network of pipeline, trunk line, and manifold are used to connect these twelve hundred wells to GCs. In order to optimize the production from NK every barrel of production opportunity has to be considered by optimizing suitable wells and minimizing downtime from each field, resulting the development of an extensive surface network model. The extensive surface network model takes into consideration of each and every details of field e.g. pipelines, manifolds, details of GCs and wells. For each and every well in NK assets a well model is prepared considering all PVT parameters, completions, and surface co-ordinate and finally connected to surface network model with all piping information.\u0000 Once the extensive surface model was prepared, several integrated workflows were developed in order to efficiently run the surface model and analyze the output from the run. Some of these workflows are ESP Optimization and ESP Analysis workflows, which have capability to identify the Oil Gain Opportunities and diagnose ESP performance. The identify opportunities are logged into ticketing system, which monitors the life cycle of the opportunity right from the identification till implementation into the field for Oil Gains.\u0000 The full-fledged development of NK-KwIDF took almost 3 years from the day it was started, as a pilot project with 133 wells. When an excellent result in terms of production optimization and downtime minimization was recorded from the pilot project, the pilot project was expanded to full-fledged field project. The NK-KwIDF project gave an outstanding result of Oil gain from well level as well as Network level optimization. It established an excellent reputation in the oil industry where it was a source of attraction for many NOC’s and IOC’s to visit and follow the flag ship for their development and implementation of digital field technology.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87428155","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
B. Ghosh, Ismail Mohammad Alcheikh, D. Ghosh, S. Osisanya
The objectives of this study were; (1) selection of size distribution of bridging particles of polymer-based drill-in fluid based on the actual reservoir porosity distribution in order to minimize the internal filtration damage, and (2) to develop a non-corrosive wellbore cleanup fluid comprising of a specially designed bio-enzyme and in-situ organic acid precursors to remove the external filter cakes and bring the skin close to zero prior to well completion. Drill-in-fluids were formulated and developed based on Ideal Packing Theory (IPT). The calcite particle size simulation was conducted using a particle size simulator based on IPT using FMI log information from a carbonate reservoir. Xanthan-starch specific bio-enzymes were screened and optimized to achieve complete dissolution of the polymers present in the mud-cakes. Acid precursors were formulated and developed to dissolve the calcite particles and at the same time keeping the corrosion level below the maximum acceptable limit. Compatibility tests between the acid precursors and the bio-enzymes were performed. The final cleanup formulation was subjected to corrosion studies at dynamic conditions. The entire development was verified at reservoir conditions through core flooding experiments. The formulated fluid was tested successfully against ceramic disks and carbonate core plugs by performing core-flood tests. The polymer based drill-in-fluid resulted in a very low permeability filter cake (<0.1 md), preventing internal filtrate damage significantly. Deposition of a very low permeability filter cake was achieved on carbonate core plugs which results in reduced damaging invasion. Several ester hydrolysis reaction kinetics were studied and finally one combination was chosen as the suitable acid precursor, because of their ability to generate required concentration of acid within three hours of hydrolysis at downhole condition. The best acid precursor satisfied the requirements by generating 3% of acid needed after 3 hours and maintained low acid concentrations for 12 hrs. The corrosion rates were found to be significantly below the industry limits and use of acid corrosion inhibitor is not necessary. Return-permeability of mud damaged carbonate core plugs was as high as 96% after exposing to clean-up solution. A new drill-in fluid has been developed and its filter-cake deposition was completely cleaned up with enzyme-acid precursor combination. Normally wellbore cleanup fluids are highly acidic and need corrosion inhibitor. The new formulation was effective in minimizing corrosion of downhole tools without the use of corrosion inhibitors.
{"title":"Towards a Zero-Skin Well Completion with Non-Damaging Non-Corrosive Enzymatic Wellbore Cleanup Fluids","authors":"B. Ghosh, Ismail Mohammad Alcheikh, D. Ghosh, S. Osisanya","doi":"10.2118/197887-ms","DOIUrl":"https://doi.org/10.2118/197887-ms","url":null,"abstract":"\u0000 The objectives of this study were; (1) selection of size distribution of bridging particles of polymer-based drill-in fluid based on the actual reservoir porosity distribution in order to minimize the internal filtration damage, and (2) to develop a non-corrosive wellbore cleanup fluid comprising of a specially designed bio-enzyme and in-situ organic acid precursors to remove the external filter cakes and bring the skin close to zero prior to well completion. Drill-in-fluids were formulated and developed based on Ideal Packing Theory (IPT). The calcite particle size simulation was conducted using a particle size simulator based on IPT using FMI log information from a carbonate reservoir. Xanthan-starch specific bio-enzymes were screened and optimized to achieve complete dissolution of the polymers present in the mud-cakes. Acid precursors were formulated and developed to dissolve the calcite particles and at the same time keeping the corrosion level below the maximum acceptable limit. Compatibility tests between the acid precursors and the bio-enzymes were performed. The final cleanup formulation was subjected to corrosion studies at dynamic conditions. The entire development was verified at reservoir conditions through core flooding experiments.\u0000 The formulated fluid was tested successfully against ceramic disks and carbonate core plugs by performing core-flood tests. The polymer based drill-in-fluid resulted in a very low permeability filter cake (<0.1 md), preventing internal filtrate damage significantly. Deposition of a very low permeability filter cake was achieved on carbonate core plugs which results in reduced damaging invasion. Several ester hydrolysis reaction kinetics were studied and finally one combination was chosen as the suitable acid precursor, because of their ability to generate required concentration of acid within three hours of hydrolysis at downhole condition. The best acid precursor satisfied the requirements by generating 3% of acid needed after 3 hours and maintained low acid concentrations for 12 hrs. The corrosion rates were found to be significantly below the industry limits and use of acid corrosion inhibitor is not necessary. Return-permeability of mud damaged carbonate core plugs was as high as 96% after exposing to clean-up solution.\u0000 A new drill-in fluid has been developed and its filter-cake deposition was completely cleaned up with enzyme-acid precursor combination. Normally wellbore cleanup fluids are highly acidic and need corrosion inhibitor. The new formulation was effective in minimizing corrosion of downhole tools without the use of corrosion inhibitors.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87493352","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Greater than 40% of global natural gas reserves are sour, with hydrogen sulfide concentrations that make processing that gas uneconomic in most cases. Furthermore, it is desirable to economically sequester acid gas contaminants from these resources due to growing environmental concerns. Current conventional technologies such as amine, cryogenic, and membrane systems typically fail to achieve the aforementioned objectives. Thus, there is a need to develop new technologies for sour gas processing. In this work, a new low temperature process for sweetening and fractionation of highly-sour natural gas is presented. The process, called "TarT", is capable of separating CO2 and H2S contaminants from the sales gas as high-purity, high-pressure streams while also recovering the NGL content of the feed gas. It is shown that the TarT process consumes about 37% less energy as compared to conventional MDEA sweetening and NGL recovery processes to produce sales gas, C4, C4+ NGL blend and high-pressure CO2 and H2S contaminant streams. The TarT process introduces a new and highly economically advantaged approach to fractionate highly-sour natural gas and sequester the resulting acidic gases.
{"title":"A Novel Low-Cost Process for Sour Gas Sweetening and NGL Recovery","authors":"Navid Rafati","doi":"10.2118/197269-ms","DOIUrl":"https://doi.org/10.2118/197269-ms","url":null,"abstract":"\u0000 Greater than 40% of global natural gas reserves are sour, with hydrogen sulfide concentrations that make processing that gas uneconomic in most cases. Furthermore, it is desirable to economically sequester acid gas contaminants from these resources due to growing environmental concerns. Current conventional technologies such as amine, cryogenic, and membrane systems typically fail to achieve the aforementioned objectives. Thus, there is a need to develop new technologies for sour gas processing.\u0000 In this work, a new low temperature process for sweetening and fractionation of highly-sour natural gas is presented. The process, called \"TarT\", is capable of separating CO2 and H2S contaminants from the sales gas as high-purity, high-pressure streams while also recovering the NGL content of the feed gas.\u0000 It is shown that the TarT process consumes about 37% less energy as compared to conventional MDEA sweetening and NGL recovery processes to produce sales gas, C4, C4+ NGL blend and high-pressure CO2 and H2S contaminant streams. The TarT process introduces a new and highly economically advantaged approach to fractionate highly-sour natural gas and sequester the resulting acidic gases.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88286603","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Gas processing plants need to cope with varying and often uncertain conditions. Operators of gas processing plants in North Dakota (USA) typically face challenges with the mode of operation (ethane rejection or ethane recovery) and feed gas uncertainty (rich gas or lean gas). In terms of equipment reliability, flexibility and efficiency, these circumstances also place significant requirements on the compressor technology used. This case study will discuss the deployment of a mechanical refrigeration cycle using commercial-grade propane (95 to 98.5% propane, with the rest being heavy hydrocarbons, or HD5, or higher-grade propane). In the context of different compressor technologies available for such applications (this includes oil flooded screw, integrally geared centrifugal or inline centrifugal, the authors examine the performance characteristics of integrally geared compressor technology applied in gas processing plants. Inherently, oil-flooded screw compressor systems require regular maintenance to ensure the availability of oil-free process gas. In turn, when seals or coalescing filters are not maintained or do not perform as expected, oil may carry over with the process gas and flows to downstream. These events require extensive cleaning and can lead to plant downtime. By comparison, integrally geared compressors and inline centrifugal compressors are 100% oil-free (no oil in compression chamber / process), providing increased reliability while requiring less maintenance. Also, integrally geared technology can be supplied with tilting pad thrust bearings which allow these propane refrigeration compressors to start at a higher suction pressure (i.e., settle out conditions on hot summer days), thus providing superior rotor stability while saving the propane because there is no need to flare the gas to reduce the system settle out pressure (Patel and Struck 2017). With regards to the parameter of flexibility, the authors will discuss how the variable diffuser guide vanes (vDGVs) are helping to provide the process flexibility, thereby extending compressor turndown up to 50% without recycle. vDGVs can maintain a required and subsequently designed discharge pressure that gives operators flexibility with varying mole weight and head requirements. vDGVs also help with start-up during high settle-out conditions like those in refrigeration processes. It was found that integrally geared compressors are about 10% more efficient than oil-flooded screw compressors. As each impeller has its own casing and seals, it will allow for easy accommodation of side streams. Also, integral gearing can match the impeller geometry to the required speed which results in higher compression efficiency, while dry gas seals reduce process gas leakage to improve plant reliability. Lastly, it was found that an integrally geared refrigerant compressor delivers more than USD 200 000 per year in OPEX savings, in addition to lower CAPEX of up to approximately 20% (based on
{"title":"Trading Risk for Reliability, Flexibility and Efficiency in NGL Plants","authors":"T. Patel, Sami Tabaza","doi":"10.2118/197496-ms","DOIUrl":"https://doi.org/10.2118/197496-ms","url":null,"abstract":"\u0000 Gas processing plants need to cope with varying and often uncertain conditions. Operators of gas processing plants in North Dakota (USA) typically face challenges with the mode of operation (ethane rejection or ethane recovery) and feed gas uncertainty (rich gas or lean gas). In terms of equipment reliability, flexibility and efficiency, these circumstances also place significant requirements on the compressor technology used. This case study will discuss the deployment of a mechanical refrigeration cycle using commercial-grade propane (95 to 98.5% propane, with the rest being heavy hydrocarbons, or HD5, or higher-grade propane). In the context of different compressor technologies available for such applications (this includes oil flooded screw, integrally geared centrifugal or inline centrifugal, the authors examine the performance characteristics of integrally geared compressor technology applied in gas processing plants.\u0000 Inherently, oil-flooded screw compressor systems require regular maintenance to ensure the availability of oil-free process gas. In turn, when seals or coalescing filters are not maintained or do not perform as expected, oil may carry over with the process gas and flows to downstream. These events require extensive cleaning and can lead to plant downtime. By comparison, integrally geared compressors and inline centrifugal compressors are 100% oil-free (no oil in compression chamber / process), providing increased reliability while requiring less maintenance. Also, integrally geared technology can be supplied with tilting pad thrust bearings which allow these propane refrigeration compressors to start at a higher suction pressure (i.e., settle out conditions on hot summer days), thus providing superior rotor stability while saving the propane because there is no need to flare the gas to reduce the system settle out pressure (Patel and Struck 2017).\u0000 With regards to the parameter of flexibility, the authors will discuss how the variable diffuser guide vanes (vDGVs) are helping to provide the process flexibility, thereby extending compressor turndown up to 50% without recycle. vDGVs can maintain a required and subsequently designed discharge pressure that gives operators flexibility with varying mole weight and head requirements. vDGVs also help with start-up during high settle-out conditions like those in refrigeration processes.\u0000 It was found that integrally geared compressors are about 10% more efficient than oil-flooded screw compressors. As each impeller has its own casing and seals, it will allow for easy accommodation of side streams. Also, integral gearing can match the impeller geometry to the required speed which results in higher compression efficiency, while dry gas seals reduce process gas leakage to improve plant reliability. Lastly, it was found that an integrally geared refrigerant compressor delivers more than USD 200 000 per year in OPEX savings, in addition to lower CAPEX of up to approximately 20% (based on","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78982745","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Replacing oil from small pores of tight rocks relies on altering the rock wettability with the injected fracturing fluid. Among different types of wettability-alteration surfactants, liquid nanofluid (LNF) has less adsorption loss during transport in the porous media and can efficiently alter the rock wettability; both make LNF a promising candidate to enhance oil recovery from tight reservoirs. In this study, a 2.5-D visualized micromodel with micro-sized pore throats is applied to elucidate the impacts of wettability alteration and spontaneous imbibition on oil-water flow in the porous media. Results provide direct evidence that the concentration of LNF changes wettability alteration rate and interfacial tension, and thus influencing the displacing rate of water into the originally oil-wet pores. This helps to optimize LNF usage in the fracturing fluid for enhanced oil recovery from tight rocks.
{"title":"A Microfluidic Study of Wettability Alteration Rate on Enhanced Oil Recovery in Oil-Wet Porous Media","authors":"Shuai Yuan, Tianbo Liang, Fu-jian Zhou, Xingyuan Liang, Fuwei Yu, Junjian Li","doi":"10.2118/197715-ms","DOIUrl":"https://doi.org/10.2118/197715-ms","url":null,"abstract":"\u0000 Replacing oil from small pores of tight rocks relies on altering the rock wettability with the injected fracturing fluid. Among different types of wettability-alteration surfactants, liquid nanofluid (LNF) has less adsorption loss during transport in the porous media and can efficiently alter the rock wettability; both make LNF a promising candidate to enhance oil recovery from tight reservoirs. In this study, a 2.5-D visualized micromodel with micro-sized pore throats is applied to elucidate the impacts of wettability alteration and spontaneous imbibition on oil-water flow in the porous media. Results provide direct evidence that the concentration of LNF changes wettability alteration rate and interfacial tension, and thus influencing the displacing rate of water into the originally oil-wet pores. This helps to optimize LNF usage in the fracturing fluid for enhanced oil recovery from tight rocks.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83514059","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Hongbin Yang, Wanli Kang, Hongwen Zhang, Bo Zhou, Xinxin Li, F. Wang
Profile control treatment is an effective technology to improve reservoir heterogeneity and decrease the watercut. Polymer gel has become the most widely used profile control agent. The most commonly used polymer in polymer gels is HPAM, which has poor adaptability in high temperature and high salinity reservoirs resulting in poor gel performance. Amphiphilic polymers have good viscosifying action in high temperature and high salinity reservoirs due to the polymer chain entanglement and hydrophobic chain association. In this paper, one amphiphilic polymer (PADC) was developed by introducing a betaine type functional monomer. In order to further improve the anti-temperature performance of PADC, the idea of using inorganic nanoparticles for enhancement was proposed. Based on this, a composite gel with good temperature and salt resistance was developed by adding crosslinking agent. The effects of nanosilica particle concentration, polymer concentration and crosslinking agent concentration on the gel performance of the composite gel were investigated systematically. The results showed that salt viscosifying action ability was related to the ionic strength. The higher the ionic strength, the larger the polymer molecular hydraulics radius. At the same time, the strength of hydrophobic association was improved and formed a denser spatial network structure. The synergistic effects made PADC have the characteristic of salt viscosifying action. It was also found that the viscoelasticity of the polymer solution changed from a viscous system to an elastic system by adding nano-silica, and apparent viscosity increased significantly. We have demonstrated that nano-silica surface will adsorb free polymer moleculesin solution, and form molecular brushes due to charge attraction and hydrogen bonding. The molecular brushes will adsorb and combine with the spatial network structure formed by the amphiphilic polymer. A significant improvement in the gel strength of composite polymer gel compared with organic polymer gel. Our work indicates that the composite gel based on amphiphilic polymer has significantly potential applications in high temperature and high salinity reservoirs, it has certain reference significance for stabilizing oil output and controlling water content for the similar reservoirs.
{"title":"The New Development of Amphiphilic Polymer Profile Control Agent in High Temperature and High Salinity Reservoirs","authors":"Hongbin Yang, Wanli Kang, Hongwen Zhang, Bo Zhou, Xinxin Li, F. Wang","doi":"10.2118/197813-ms","DOIUrl":"https://doi.org/10.2118/197813-ms","url":null,"abstract":"\u0000 Profile control treatment is an effective technology to improve reservoir heterogeneity and decrease the watercut. Polymer gel has become the most widely used profile control agent. The most commonly used polymer in polymer gels is HPAM, which has poor adaptability in high temperature and high salinity reservoirs resulting in poor gel performance. Amphiphilic polymers have good viscosifying action in high temperature and high salinity reservoirs due to the polymer chain entanglement and hydrophobic chain association. In this paper, one amphiphilic polymer (PADC) was developed by introducing a betaine type functional monomer. In order to further improve the anti-temperature performance of PADC, the idea of using inorganic nanoparticles for enhancement was proposed. Based on this, a composite gel with good temperature and salt resistance was developed by adding crosslinking agent. The effects of nanosilica particle concentration, polymer concentration and crosslinking agent concentration on the gel performance of the composite gel were investigated systematically. The results showed that salt viscosifying action ability was related to the ionic strength. The higher the ionic strength, the larger the polymer molecular hydraulics radius. At the same time, the strength of hydrophobic association was improved and formed a denser spatial network structure. The synergistic effects made PADC have the characteristic of salt viscosifying action. It was also found that the viscoelasticity of the polymer solution changed from a viscous system to an elastic system by adding nano-silica, and apparent viscosity increased significantly. We have demonstrated that nano-silica surface will adsorb free polymer moleculesin solution, and form molecular brushes due to charge attraction and hydrogen bonding. The molecular brushes will adsorb and combine with the spatial network structure formed by the amphiphilic polymer. A significant improvement in the gel strength of composite polymer gel compared with organic polymer gel. Our work indicates that the composite gel based on amphiphilic polymer has significantly potential applications in high temperature and high salinity reservoirs, it has certain reference significance for stabilizing oil output and controlling water content for the similar reservoirs.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88844083","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Complex hydrocarbon distributions where reservoirs are filled by oil and gas phases with different densities and genetic types interfingering within a basin are a common phenomenon in Southeast Asia and are often attributed to vertical migration. Attempts to understanding the controlling factors of vertical hydrocarbon migration by modeling the hydrocarbon charging and entrapment history from two Cenozoic basins in Southeast Asia—West Java and the Madura Platform—are discussed. A modified invasion percolation algorithm was used to simulate the secondary migration models, which follows the principle that migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy and capillary forces. Three-dimensional (3D) seismic data were used as the base grid for migration simulation to capture the effect of both structure and facies variations on fluid flow. Two models, one from the West Java Basin (fault-bounded structure) and the East Java Basin (nonfault-bounded structure), are presented. For both cases, interfingering between oil and gas occurred, with most oils trapped within the lower formations, a mixture of oil and gas dominates the middle formations, and mostly gas in the upper formation. These vertical arrangements are possible because of the relatively weak formational seals within the basin. For vertically distributed reservoirs, oil is often trapped within the lower interval, and gas is trapped at the upper interval. For a basin dominated by a vertical migration regime, the potential risk for hydrocarbon lateral travel far away from the kitchen is high, thus increasing the potential risk of prospectivity away from the kitchen. Understanding factors that help control vertical migration also help geologists better understand hydrocarbon distributions within the basins. Case studies during which modeling helped determine the factors that influenced vertical hydrocarbon migration and the resulting potential phase distribution prospectivity risks in the studied basins are discussed.
{"title":"Case for Vertical Hydrocarbon Migration: Case Studies, Southeast Asia Tertiary Basins","authors":"G. Christopher","doi":"10.2118/197815-ms","DOIUrl":"https://doi.org/10.2118/197815-ms","url":null,"abstract":"\u0000 Complex hydrocarbon distributions where reservoirs are filled by oil and gas phases with different densities and genetic types interfingering within a basin are a common phenomenon in Southeast Asia and are often attributed to vertical migration. Attempts to understanding the controlling factors of vertical hydrocarbon migration by modeling the hydrocarbon charging and entrapment history from two Cenozoic basins in Southeast Asia—West Java and the Madura Platform—are discussed.\u0000 A modified invasion percolation algorithm was used to simulate the secondary migration models, which follows the principle that migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy and capillary forces. Three-dimensional (3D) seismic data were used as the base grid for migration simulation to capture the effect of both structure and facies variations on fluid flow.\u0000 Two models, one from the West Java Basin (fault-bounded structure) and the East Java Basin (nonfault-bounded structure), are presented. For both cases, interfingering between oil and gas occurred, with most oils trapped within the lower formations, a mixture of oil and gas dominates the middle formations, and mostly gas in the upper formation. These vertical arrangements are possible because of the relatively weak formational seals within the basin. For vertically distributed reservoirs, oil is often trapped within the lower interval, and gas is trapped at the upper interval. For a basin dominated by a vertical migration regime, the potential risk for hydrocarbon lateral travel far away from the kitchen is high, thus increasing the potential risk of prospectivity away from the kitchen. Understanding factors that help control vertical migration also help geologists better understand hydrocarbon distributions within the basins.\u0000 Case studies during which modeling helped determine the factors that influenced vertical hydrocarbon migration and the resulting potential phase distribution prospectivity risks in the studied basins are discussed.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91336963","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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