Flow assurance ensures that geothermal fluids (hot water and steam) flow properly in a pipe or well and are transferred to a power plant safely and cost-effectively. Inorganic deposition (scales) is regarded as the primary issue in geothermal fluid flow, and a reliable controlling strategy to predict and prevent scaling is essential. We introduced a practical scale integrity management strategy to predict and prevent scaling in the flowline to achieve this goal. Thermochemical modeling is the primary predictive model to predict why, where, and when scaling will occur. Then two treatment approaches (chemical and non-chemical) are investigated to prevent and treat scaling. What-if analysis is extensively applied to propose an economic plan. Due to the inability of laboratory research to replicate the extreme pressures and temperatures of geothermal wells, experts do not know precisely when and how minerals dissolve down in the well and are unable to offer regulating recommendations. Therefore, an efficient scale integrity management plan must be implemented. Simulation tools play a significant part in the development of flow assurance, as they provide a consistent framework for testing various what-if scenarios and aid in making the best operational solution. Injecting chemicals is not always economical to control scaling in geothermal operation due to the cost and inefficiency in high-pressure and high-temperature situations in these wells, and the non-chemical approach should be prioritized. Potential non-chemical approaches include sulfate reduction, operating wells outside critical scaling envelopes, reinjecting produced water, and lifting gas injection with more CO2. This research intends to broaden the flow assurance concept in geothermal wells by analyzing the impediments and treatments from wells to the surface facilities.
{"title":"Flow Assurance Management in Geothermal Production Wells","authors":"R. Matoorian, M. Malaieri","doi":"10.2118/212144-ms","DOIUrl":"https://doi.org/10.2118/212144-ms","url":null,"abstract":"\u0000 Flow assurance ensures that geothermal fluids (hot water and steam) flow properly in a pipe or well and are transferred to a power plant safely and cost-effectively. Inorganic deposition (scales) is regarded as the primary issue in geothermal fluid flow, and a reliable controlling strategy to predict and prevent scaling is essential.\u0000 We introduced a practical scale integrity management strategy to predict and prevent scaling in the flowline to achieve this goal. Thermochemical modeling is the primary predictive model to predict why, where, and when scaling will occur. Then two treatment approaches (chemical and non-chemical) are investigated to prevent and treat scaling. What-if analysis is extensively applied to propose an economic plan.\u0000 Due to the inability of laboratory research to replicate the extreme pressures and temperatures of geothermal wells, experts do not know precisely when and how minerals dissolve down in the well and are unable to offer regulating recommendations. Therefore, an efficient scale integrity management plan must be implemented. Simulation tools play a significant part in the development of flow assurance, as they provide a consistent framework for testing various what-if scenarios and aid in making the best operational solution. Injecting chemicals is not always economical to control scaling in geothermal operation due to the cost and inefficiency in high-pressure and high-temperature situations in these wells, and the non-chemical approach should be prioritized. Potential non-chemical approaches include sulfate reduction, operating wells outside critical scaling envelopes, reinjecting produced water, and lifting gas injection with more CO2.\u0000 This research intends to broaden the flow assurance concept in geothermal wells by analyzing the impediments and treatments from wells to the surface facilities.","PeriodicalId":422875,"journal":{"name":"Day 2 Wed, November 30, 2022","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-11-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127846675","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}
This paper presents the key aspects of nitrogen-assisted cyclic steam stimulation field trial at Post-CHOPS wells in FNE field, Sudan. FNE field is a heavy-oil asset with compositional gradient (13.87 to 18.1°API, in-situ viscosity of 226 to 255 cp) in massive unconsolidated sandstones at depths of 1,500 to 1,900 ft, with a permeability of 2 to 9 Darcies and strong bottom-water drive. Initially, cold heavy oil production with sand (CHOPS) was applied to exploit easy oil at upper zones of entire play. When flow rates of CHOPS wells declined to economic limits, or producers were too cool (reservoir temperature 111°F) to pump efficiently, nitrogen-assisted cyclic steam stimulation was to increase reservoir pressure, decrease heavy-oil viscosity, and boost well production. The specific technical points are highlighted below: In-house studies, including viscosity reduction test and numerical simulations, recommended that steam volume (cold-water equivalent) of 11,442 bbl per cycle based on 268 bbl/ft, with 70 to 75% quality, will be injected into the reservoir at rate of 1,260 bbl/d, nitrogen injection volume per cycle is 4.75 MMscf, soak time is for 5 to 7 days to allow the heat and pressure to distribute more uniform through the reservoir, then go to puff process. Pump is set 30-60 ft below the lowermost perforations to maximize fluids production through keeping fluid-level well below bottom perforations. By the end of pumping, bottomhole flowing pressure can declined to 70 psi. Steam and nitrogen injection sequence at updip wells is to inject steam first, followed by nitrogen injection. For downdip wells, nitrogen injection is the first and steam injection comes later to mitigate water influx. Re-completion strategy: squeeze cement into CHOPS producing zones because they contain wormholes, some communicating with aquifer, and perforate the lower pay interval to extract more viscous heavy oil. Failure risk assessment of production casings: pre-tensioning and full cementing of the casing with thermal cement is adopted in CHOPS wells for post-CHOPS thermal operation. Initial flowback flow rate is limited to less than the level of 500 bbl/d to reduce sanding risk and does not unduly de-pressure the formation at initial production. During pumping process, all fluids are exploited up the tubing string and the annulus is vented the flow-line. Pump works at optimal rate to ensure pressure drawdown less than critical drawdown threshold for sanding and water coning. Field data confirmed that this trial is successful, with 2 to 3-fold production gain, relatively low water cut and no sanding issue. This technology is a useful option for post-CHOPS wells in the similar heavy-oil assets.
{"title":"Field Trial of Nitrogen-Assisted Cyclic Steam Stimulation in Post-CHOPS Wells, Case Study in Sudan","authors":"Xueqing Tang, Chun-xu Yu, Yang Bai, Hui Lu, Mohamed Salaheldin Mohamed","doi":"10.2118/212147-ms","DOIUrl":"https://doi.org/10.2118/212147-ms","url":null,"abstract":"\u0000 This paper presents the key aspects of nitrogen-assisted cyclic steam stimulation field trial at Post-CHOPS wells in FNE field, Sudan. FNE field is a heavy-oil asset with compositional gradient (13.87 to 18.1°API, in-situ viscosity of 226 to 255 cp) in massive unconsolidated sandstones at depths of 1,500 to 1,900 ft, with a permeability of 2 to 9 Darcies and strong bottom-water drive. Initially, cold heavy oil production with sand (CHOPS) was applied to exploit easy oil at upper zones of entire play. When flow rates of CHOPS wells declined to economic limits, or producers were too cool (reservoir temperature 111°F) to pump efficiently, nitrogen-assisted cyclic steam stimulation was to increase reservoir pressure, decrease heavy-oil viscosity, and boost well production. The specific technical points are highlighted below:\u0000 In-house studies, including viscosity reduction test and numerical simulations, recommended that steam volume (cold-water equivalent) of 11,442 bbl per cycle based on 268 bbl/ft, with 70 to 75% quality, will be injected into the reservoir at rate of 1,260 bbl/d, nitrogen injection volume per cycle is 4.75 MMscf, soak time is for 5 to 7 days to allow the heat and pressure to distribute more uniform through the reservoir, then go to puff process. Pump is set 30-60 ft below the lowermost perforations to maximize fluids production through keeping fluid-level well below bottom perforations. By the end of pumping, bottomhole flowing pressure can declined to 70 psi. Steam and nitrogen injection sequence at updip wells is to inject steam first, followed by nitrogen injection. For downdip wells, nitrogen injection is the first and steam injection comes later to mitigate water influx. Re-completion strategy: squeeze cement into CHOPS producing zones because they contain wormholes, some communicating with aquifer, and perforate the lower pay interval to extract more viscous heavy oil. Failure risk assessment of production casings: pre-tensioning and full cementing of the casing with thermal cement is adopted in CHOPS wells for post-CHOPS thermal operation. Initial flowback flow rate is limited to less than the level of 500 bbl/d to reduce sanding risk and does not unduly de-pressure the formation at initial production. During pumping process, all fluids are exploited up the tubing string and the annulus is vented the flow-line. Pump works at optimal rate to ensure pressure drawdown less than critical drawdown threshold for sanding and water coning.\u0000 Field data confirmed that this trial is successful, with 2 to 3-fold production gain, relatively low water cut and no sanding issue. This technology is a useful option for post-CHOPS wells in the similar heavy-oil assets.","PeriodicalId":422875,"journal":{"name":"Day 2 Wed, November 30, 2022","volume":"40 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-11-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122444593","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}
Fernancelys Rodriguez, M. Llamedo, H. Belhaj, A. Belhaj
Acid gases production, such as hydrogen sulfide and carbon dioxide, from heavy oil reservoirs in Venezuela is generally associated with the application of thermal enhanced oil recovery methods. These undesired gases, especially H2S, can be removed by injecting chemical additives that promote chemical reactions with oxidative or nonoxidative mechanisms in the producing system to generate fewer toxic byproducts. According to the literature, H2S scavengers evaluated in the oil industry are amines, alkaline sodium nitrite, hydrogen peroxide, triazine, among others. To mitigate both H2S and CO2 from a reservoir, some novel proposals are under study to offer alternatives to control them from the reservoir and reduce their production in surface. This article presents a review of the key parameters that play a role in the generation of acid gases, mainly H2S and CO2, in Venezuelan oil reservoirs. The operational field data, the main reactions and mechanisms involved in the process (e.g., aquathermolysis, hydro pyrolysis), and the type of byproducts generated will be reviewed. The results and knowledge gained will assist in identifying the main insights of the process, associating them with other international field cases published in the literature, and establishing perspectives for the evaluation of the most convenient techniques from health, safety, technical and economic points of view. Lab and field results have shown that the application of thermal EOR methods in reservoirs of the main Venezuelan basins promote the generation of acid gases due to physicochemical transformations of sulfur, and/or fluid-rock interactions. Sulfur content in Venezuelan viscous oil reservoirs, together with rock mineralogy (clay type) has a significant impact on H2S production. Reported lab results also indicated that H2S scavengers reduce the amount of sulfur, and the presence of CO2 also affects the H2S removal mechanisms, depending on which type of scavenger is selected (e.g., amines, triazine, etc.). Solubilization, hydrolysis, adsorption, absorption, and complex sequestrant reactions (oxidation, neutralization, regeneration, and precipitations) are the main mechanisms involved in the removal of H2S. The literature reported that the application of triazine liquid scavengers is found to generate monomeric dithiazine byproducts (amorphous polymeric dithiazine) which might cause formation damage or inflict flow assurance issues upstream and downstream. This work presents a state of the art review on H2S generation mechanisms and new technologies for the mitigation of acid gases in Venezuelan reservoirs. It also provides perspectives for the application of the most convenient technologies for the reduction of greenhouse gas emissions (mostly CO2), which is critical to producing hydrocarbons with low environmental impact.
{"title":"Challenges Associated with the Acid Gases Production and Capture in Hydrocarbon Reservoirs: A Critical Review of the Venezuelan Cases","authors":"Fernancelys Rodriguez, M. Llamedo, H. Belhaj, A. Belhaj","doi":"10.2118/212146-ms","DOIUrl":"https://doi.org/10.2118/212146-ms","url":null,"abstract":"\u0000 Acid gases production, such as hydrogen sulfide and carbon dioxide, from heavy oil reservoirs in Venezuela is generally associated with the application of thermal enhanced oil recovery methods. These undesired gases, especially H2S, can be removed by injecting chemical additives that promote chemical reactions with oxidative or nonoxidative mechanisms in the producing system to generate fewer toxic byproducts. According to the literature, H2S scavengers evaluated in the oil industry are amines, alkaline sodium nitrite, hydrogen peroxide, triazine, among others. To mitigate both H2S and CO2 from a reservoir, some novel proposals are under study to offer alternatives to control them from the reservoir and reduce their production in surface.\u0000 This article presents a review of the key parameters that play a role in the generation of acid gases, mainly H2S and CO2, in Venezuelan oil reservoirs. The operational field data, the main reactions and mechanisms involved in the process (e.g., aquathermolysis, hydro pyrolysis), and the type of byproducts generated will be reviewed. The results and knowledge gained will assist in identifying the main insights of the process, associating them with other international field cases published in the literature, and establishing perspectives for the evaluation of the most convenient techniques from health, safety, technical and economic points of view.\u0000 Lab and field results have shown that the application of thermal EOR methods in reservoirs of the main Venezuelan basins promote the generation of acid gases due to physicochemical transformations of sulfur, and/or fluid-rock interactions. Sulfur content in Venezuelan viscous oil reservoirs, together with rock mineralogy (clay type) has a significant impact on H2S production. Reported lab results also indicated that H2S scavengers reduce the amount of sulfur, and the presence of CO2 also affects the H2S removal mechanisms, depending on which type of scavenger is selected (e.g., amines, triazine, etc.). Solubilization, hydrolysis, adsorption, absorption, and complex sequestrant reactions (oxidation, neutralization, regeneration, and precipitations) are the main mechanisms involved in the removal of H2S. The literature reported that the application of triazine liquid scavengers is found to generate monomeric dithiazine byproducts (amorphous polymeric dithiazine) which might cause formation damage or inflict flow assurance issues upstream and downstream.\u0000 This work presents a state of the art review on H2S generation mechanisms and new technologies for the mitigation of acid gases in Venezuelan reservoirs. It also provides perspectives for the application of the most convenient technologies for the reduction of greenhouse gas emissions (mostly CO2), which is critical to producing hydrocarbons with low environmental impact.","PeriodicalId":422875,"journal":{"name":"Day 2 Wed, November 30, 2022","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-11-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128137279","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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