As operators focus on harvesting stranded reserves from existing infrastructures, specific technical challenges and ROI calculations are affecting sand control completion selection and putting screen design requirements in a new light. In-fill drilling and completion of sidetracked wells in depleted reservoirs are not favorable to gravel packing because low hydraulic frac pressures and small wellbores make conventional gravel packing operations incredibly challenging, if not downright impossible. Furthermore, gravel packing is selected when operators are looking for a long-term sand control solution warranted by significant reserves, something that is not necessarily present in brown field redevelopments. As a result, there is a need to improve stand-alone completions, and particularly improve the erosion resistance of screens that have been known to fail by hot spotting, where localized high flow situations erode the screen and lead to completion failure. A series of time lapse erosion tests was conducted to identify critical damaging mechanisms and evaluate solutions, including mesh materials and design features to improve the erosion resistance of mesh screens. The test program included detailed examination of the test coupons in frequent intervals to identify wear features and trends over time. This approach to testing was instrumental in characterizing damaging backward eddies inside the screen and developing solutions to mitigate their impact. From this test campaign, two new features were found to substantially improve screen erosion resistance. A hardening process to treat meshes commonly used in screens increased the Mean Time to Failure (MMTF) by 50%. Furthermore, a novel shielding concept aimed at preventing direct line-of-sight flow to the basepipe perforations (while maintaining the filter surface area and good flow distribution over the screen length) reduced mesh weight loss by 75% and maintained the original maximum pore size beyond the 72hour success criteria, for an estimated MTTF improvement well over 300%.
{"title":"Time Lapse Wear Study Yields New Design Features to Improve the Erosion Resistance of Stand-Alone Screen Completions","authors":"C. Malbrel, R. Kale","doi":"10.2118/208817-ms","DOIUrl":"https://doi.org/10.2118/208817-ms","url":null,"abstract":"\u0000 As operators focus on harvesting stranded reserves from existing infrastructures, specific technical challenges and ROI calculations are affecting sand control completion selection and putting screen design requirements in a new light. In-fill drilling and completion of sidetracked wells in depleted reservoirs are not favorable to gravel packing because low hydraulic frac pressures and small wellbores make conventional gravel packing operations incredibly challenging, if not downright impossible. Furthermore, gravel packing is selected when operators are looking for a long-term sand control solution warranted by significant reserves, something that is not necessarily present in brown field redevelopments. As a result, there is a need to improve stand-alone completions, and particularly improve the erosion resistance of screens that have been known to fail by hot spotting, where localized high flow situations erode the screen and lead to completion failure.\u0000 A series of time lapse erosion tests was conducted to identify critical damaging mechanisms and evaluate solutions, including mesh materials and design features to improve the erosion resistance of mesh screens. The test program included detailed examination of the test coupons in frequent intervals to identify wear features and trends over time. This approach to testing was instrumental in characterizing damaging backward eddies inside the screen and developing solutions to mitigate their impact.\u0000 From this test campaign, two new features were found to substantially improve screen erosion resistance. A hardening process to treat meshes commonly used in screens increased the Mean Time to Failure (MMTF) by 50%. Furthermore, a novel shielding concept aimed at preventing direct line-of-sight flow to the basepipe perforations (while maintaining the filter surface area and good flow distribution over the screen length) reduced mesh weight loss by 75% and maintained the original maximum pore size beyond the 72hour success criteria, for an estimated MTTF improvement well over 300%.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"183 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91526633","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}
Oil and gas production or water injection is sometimes hampered by wellbore scales and fills (i.e., inner well flow impediments) as well as formation damage (skin) that impedes flow. Formation damage may reside in the near wellbore region but could also extend deep into the formation. While the severity of the skin may vary from well to well the mechanisms of damage are generally mechanical, chemical, biological, or thermal in nature. Whereas a formation with no damage would have a skin factor of zero a well with serious damage may have a skin factor of 20 or greater. Formation damage impairs rock permeability which directly impacts oil and gas production or water injection operations hence the economics of the oil and gas field. Well stimulations to address formation damage are accomplished through a variety of techniques but most commonly through chemical (acid) treatments to restore a wells productivity or injectivity. Often, due to permeability heterogeneity, common stimulation approaches do not provide maximum volumetric contact of treatment fluids with the formation. To maximize volumetric contact of the treatment fluid with the formation and across the entire completed interval, it is of utmost importance to employ a technique that can overcome the challenges of permeability heterogeneity to improve post-stimulation outcomes.
{"title":"Evaluating the Performance of Fluid Placement Approaches on Well Stimulation Results","authors":"Sanjiv Kumar, B. Davidson, A. Abouakar","doi":"10.2118/208848-ms","DOIUrl":"https://doi.org/10.2118/208848-ms","url":null,"abstract":"\u0000 Oil and gas production or water injection is sometimes hampered by wellbore scales and fills (i.e., inner well flow impediments) as well as formation damage (skin) that impedes flow. Formation damage may reside in the near wellbore region but could also extend deep into the formation. While the severity of the skin may vary from well to well the mechanisms of damage are generally mechanical, chemical, biological, or thermal in nature. Whereas a formation with no damage would have a skin factor of zero a well with serious damage may have a skin factor of 20 or greater. Formation damage impairs rock permeability which directly impacts oil and gas production or water injection operations hence the economics of the oil and gas field.\u0000 Well stimulations to address formation damage are accomplished through a variety of techniques but most commonly through chemical (acid) treatments to restore a wells productivity or injectivity. Often, due to permeability heterogeneity, common stimulation approaches do not provide maximum volumetric contact of treatment fluids with the formation. To maximize volumetric contact of the treatment fluid with the formation and across the entire completed interval, it is of utmost importance to employ a technique that can overcome the challenges of permeability heterogeneity to improve post-stimulation outcomes.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83188396","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}
Faisal M. Alissa, Norah W. Aljuryyed, Salem A. Balharth, M. Leoni
Calcium sulfate scale is one of the challenges that face production stability in the oilfield industry as it is one of the most challenging scales to manage. Sulfate-scales are very hard to dissolve because of their low solubility-product. This work studies the dissolution capacity of different chemical additives and recipes on calcium sulfate scales. In this work, the maximum dissolution capacity (gram of scale/mole of chelating agent) of various chemical additives and recipes will be studied to evaluate the efficiency in the dissolution of Calcium Sulfate scales. Several experiments were conducted at multiple doses, pH, and in-presence of a catalyst. Potassium Carbonate was used as a catalyst in the dissolution of Calcium Sulfate scales. The performance of each additive was studied in a catalyzed and non-catalyzed pathway and with various. A Series of experiments conducted showed that parameters such as the additive-dose, pH, and a catalyst affect the dissolution efficiency. The dissolution performance efficiency of each additive (Lactic Acid, Citric Acid, L-Glutamic Acid-N, N-diacetic Acid (GLDA), and Gluconic Acid) was compared to the additive performance efficiency under a catalyzed pathway in a formulated recipe. The outcome of this work will contribute to the economic value added by finding the most efficient and cheap recipe to remove Calcium Sulfate scales from the wellbore.
{"title":"Calcium Sulfate Scale Dissolution Efficiency by Various Chemicals Additives","authors":"Faisal M. Alissa, Norah W. Aljuryyed, Salem A. Balharth, M. Leoni","doi":"10.2118/208819-ms","DOIUrl":"https://doi.org/10.2118/208819-ms","url":null,"abstract":"\u0000 Calcium sulfate scale is one of the challenges that face production stability in the oilfield industry as it is one of the most challenging scales to manage. Sulfate-scales are very hard to dissolve because of their low solubility-product. This work studies the dissolution capacity of different chemical additives and recipes on calcium sulfate scales. In this work, the maximum dissolution capacity (gram of scale/mole of chelating agent) of various chemical additives and recipes will be studied to evaluate the efficiency in the dissolution of Calcium Sulfate scales. Several experiments were conducted at multiple doses, pH, and in-presence of a catalyst. Potassium Carbonate was used as a catalyst in the dissolution of Calcium Sulfate scales. The performance of each additive was studied in a catalyzed and non-catalyzed pathway and with various. A Series of experiments conducted showed that parameters such as the additive-dose, pH, and a catalyst affect the dissolution efficiency. The dissolution performance efficiency of each additive (Lactic Acid, Citric Acid, L-Glutamic Acid-N, N-diacetic Acid (GLDA), and Gluconic Acid) was compared to the additive performance efficiency under a catalyzed pathway in a formulated recipe. The outcome of this work will contribute to the economic value added by finding the most efficient and cheap recipe to remove Calcium Sulfate scales from the wellbore.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75202665","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}
Huifeng Liu, P. Bedrikovetsky, Y. Osipov, Maotang Yao, Fuguo Xia, Jiaxue Li, Jianbo Li
Water flooding is extensively used in the industry to develop the mature oilfields. However, after several years’ of injection, the injectivity usually declines and the injection pressure increases. This is because the solid or liquid particles in the injected water are retained in the pores and block the flow channel in the near wellbore region. The prediction of the particle retention and permeability damage is important for the design of damage removal methods like acidizing. Previous researchers including M. Nunes, P. Bedrikovetsky, Feike J. Leij, et al. have done some work on the analytical solutions of the flow of particulate suspension in porous media with particle retention and consequent permeability reduction. However, they either assumed one-dimensional linear flow in the porous media or took the filtration coefficient as a constant. These are not always true because the flow of the injected water near the wellbore is radial and the filtration coefficient tends to decline with more and more particles being retained in the pores and ultimately reaches zero when all channels are blocked. In this paper, we established a near-wellbore axisymmetric suspension flow and particle retention model based on Langmuirian blocking, obtained the approximate analytical solution and compared it with the numerical solution. The results showed that the error of our approximate solution for the retained particle concentration is within 5%. Then we incorporated the analytical expression into the Darcy's law equation and derived the expression of pressure drop as well as skin factor caused by particle retention. Damaged zone radius was also defined so as to estimate the acid volume needed to remove the damage. We also checked our models and solutions using field cases of water injection and acidizing from Tarim Oilfields, western China. The results showed that the injection pressure drop due to particle retention and the injection pressure recover after acidizing calculated from our models are basically consistent with the actual situation. Our models can be further used to predict the damage zone radius and design the acid volume for damage removal. The analytical solution can also be used to perform sensitivity analysis for the parameters involved.
注水开发是目前工业上广泛应用的成熟油田开发方法。然而，经过几年的注入，注入能力通常会下降，注入压力会增加。这是因为注入水中的固体或液体颗粒被保留在孔隙中，阻塞了近井筒区域的流动通道。颗粒滞留和渗透率损伤的预测对酸化等除损伤方法的设计具有重要意义。M. Nunes, P. Bedrikovetsky, Feike J. Leij等先前的研究人员已经对颗粒悬浮液在多孔介质中流动的解析解进行了一些研究，其中颗粒滞留导致渗透率降低。然而，他们要么假设多孔介质中的一维线性流动，要么将过滤系数作为常数。但这并不总是正确的，因为注入水在井筒附近的流动是径向的，随着越来越多的颗粒滞留在孔隙中，过滤系数趋于下降，当所有通道都被堵塞时，过滤系数最终趋于零。本文建立了基于Langmuirian阻塞的近井筒轴对称悬浮流动与颗粒滞留模型，得到了近似解析解，并与数值解进行了比较。结果表明，近似解的误差在5%以内。然后将解析表达式代入达西定律方程，推导出颗粒滞留引起的压降和表皮因子的表达式。还定义了受损区域半径，以便估计清除损害所需的酸量。并以塔里木油田注水酸化的现场实例对模型和解决方案进行了验证。结果表明，模型计算的颗粒滞留引起的注入压降和酸化后恢复的注入压力与实际情况基本一致。我们的模型可以进一步用于预测损伤区域半径和设计去除损伤的酸体积。该解析解还可用于对所涉及的参数进行灵敏度分析。
{"title":"An Approximate Analytical Solution for Damage Radius Prediction in Water Injection Wells Based on Langmuirian Blocking: Derivation, Comparison and Field Applications","authors":"Huifeng Liu, P. Bedrikovetsky, Y. Osipov, Maotang Yao, Fuguo Xia, Jiaxue Li, Jianbo Li","doi":"10.2118/208872-ms","DOIUrl":"https://doi.org/10.2118/208872-ms","url":null,"abstract":"\u0000 Water flooding is extensively used in the industry to develop the mature oilfields. However, after several years’ of injection, the injectivity usually declines and the injection pressure increases. This is because the solid or liquid particles in the injected water are retained in the pores and block the flow channel in the near wellbore region. The prediction of the particle retention and permeability damage is important for the design of damage removal methods like acidizing.\u0000 Previous researchers including M. Nunes, P. Bedrikovetsky, Feike J. Leij, et al. have done some work on the analytical solutions of the flow of particulate suspension in porous media with particle retention and consequent permeability reduction. However, they either assumed one-dimensional linear flow in the porous media or took the filtration coefficient as a constant. These are not always true because the flow of the injected water near the wellbore is radial and the filtration coefficient tends to decline with more and more particles being retained in the pores and ultimately reaches zero when all channels are blocked.\u0000 In this paper, we established a near-wellbore axisymmetric suspension flow and particle retention model based on Langmuirian blocking, obtained the approximate analytical solution and compared it with the numerical solution. The results showed that the error of our approximate solution for the retained particle concentration is within 5%. Then we incorporated the analytical expression into the Darcy's law equation and derived the expression of pressure drop as well as skin factor caused by particle retention. Damaged zone radius was also defined so as to estimate the acid volume needed to remove the damage. We also checked our models and solutions using field cases of water injection and acidizing from Tarim Oilfields, western China. The results showed that the injection pressure drop due to particle retention and the injection pressure recover after acidizing calculated from our models are basically consistent with the actual situation. Our models can be further used to predict the damage zone radius and design the acid volume for damage removal. The analytical solution can also be used to perform sensitivity analysis for the parameters involved.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"126 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74401655","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}
Anastasia Bird, J. Espinoza-Perez, Karthik Mahadev, John Sixt
Glass reinforced epoxy (GRE) lining is a polymer composite material, the main components of which are a thermosetting resin and a fiberglass reinforcement. The combined properties of its components result in a material with excellent chemical, thermal and mechanical performance. GRE lining is typically used as a coating on production tubulars in oil wells to protect metallurgy of tubulars from corrosive environments, thereby extending the life of tubulars and realizing cost savings. GRE lining is chemically compatible with many acids used in well stimulation to restore productivity. Typical acids such as hydrochloric, formic, acetic etc. involve carbonate removal followed using hydrofluoric (HF) based acids for removal of small formation particles. However, the use of HF is typically not recommended in GRE lined tubulars due to potential interactions with HF. Yet, in most sandstone reservoirs, HF fluids contribute greatly to restoring well productivity due to formation damage removal related to fines and clays. While GRE lining is a well-known technology, its chemical compatibility with acids is challenging to predict due to its heterogenous nature and requires specific testing to understand potential for mechanical degradation. Prior studies at BP focused on evaluation of GRE performance with 9% HCl: 1% HF under ambient boundary conditions of 77°F for 24 hours. These tests caused unacceptable levels of mechanical degradation to GRE and plans to execute stimulation treatments in GRE lined wells were abandoned. However, an increasing number of GRE lined underperforming water injector well stock necessitated a less aggressive acid design involving 0.5% HF. Therefore, 0.5% HF was assessed for GRE lining compatibility, mechanical and physical property changes under specific well boundary conditions at elevated temperatures of 120°F and 140°F and extended times of up to 72 hours. Core flow tests were also carried out to evaluate the effect of GRE exposed acid to any potential for formation damage. This study demonstrated that exposure of GRE lining to 0.5% HF resulted in acceptable retention of mechanical properties and did not show any formation damage impacts. These results were also reflected in field performance where a significant injectivity index improvement of >4 was achieved, thereby opening the door to a significant increase in number of GRE lined wells to be treated across multiple regions.
{"title":"Stimulation Treatment Design Compatible with Glass Reinforced Epoxy Lining","authors":"Anastasia Bird, J. Espinoza-Perez, Karthik Mahadev, John Sixt","doi":"10.2118/208807-ms","DOIUrl":"https://doi.org/10.2118/208807-ms","url":null,"abstract":"\u0000 Glass reinforced epoxy (GRE) lining is a polymer composite material, the main components of which are a thermosetting resin and a fiberglass reinforcement. The combined properties of its components result in a material with excellent chemical, thermal and mechanical performance. GRE lining is typically used as a coating on production tubulars in oil wells to protect metallurgy of tubulars from corrosive environments, thereby extending the life of tubulars and realizing cost savings. GRE lining is chemically compatible with many acids used in well stimulation to restore productivity. Typical acids such as hydrochloric, formic, acetic etc. involve carbonate removal followed using hydrofluoric (HF) based acids for removal of small formation particles. However, the use of HF is typically not recommended in GRE lined tubulars due to potential interactions with HF. Yet, in most sandstone reservoirs, HF fluids contribute greatly to restoring well productivity due to formation damage removal related to fines and clays. While GRE lining is a well-known technology, its chemical compatibility with acids is challenging to predict due to its heterogenous nature and requires specific testing to understand potential for mechanical degradation.\u0000 Prior studies at BP focused on evaluation of GRE performance with 9% HCl: 1% HF under ambient boundary conditions of 77°F for 24 hours. These tests caused unacceptable levels of mechanical degradation to GRE and plans to execute stimulation treatments in GRE lined wells were abandoned. However, an increasing number of GRE lined underperforming water injector well stock necessitated a less aggressive acid design involving 0.5% HF. Therefore, 0.5% HF was assessed for GRE lining compatibility, mechanical and physical property changes under specific well boundary conditions at elevated temperatures of 120°F and 140°F and extended times of up to 72 hours. Core flow tests were also carried out to evaluate the effect of GRE exposed acid to any potential for formation damage.\u0000 This study demonstrated that exposure of GRE lining to 0.5% HF resulted in acceptable retention of mechanical properties and did not show any formation damage impacts. These results were also reflected in field performance where a significant injectivity index improvement of >4 was achieved, thereby opening the door to a significant increase in number of GRE lined wells to be treated across multiple regions.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"64 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74419185","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}
Water production from oil and gas wells increases lift costs and produces production problems such as effluent discharge limits, separation difficulties, fouling and corrosion. This is becoming more of a challenge in these times where the Carbon footprint of new oil and gas installations is under tighter environmental scrutiny. Therefore, prolonging the life of existing wells in an environmentally friendly and economic way is becoming increasingly important. As water production increases the profitability of a well typically decreases due to the costs incurred in dealing with the problems mentioned above. While several engineering solutions for curbing excessive water production exist, the cost of such solutions typically outweigh the benefits, hence favouring the use of chemicals. For chemicals to be successful, case by case evaluation is required. This paper examines the successful screening and evaluation of relative permeability modifiers for water control in the field. Two relative permeability modifier chemicals (RPM A and RPM B) were selected for evaluation under simulated reservoir conditions. Prior to core flood testing, both chemicals were examined for stability and compatibility with formation fluids. While RPM B showed some signs of instability, ultimately, both chemicals were assessed under simulated reservoir conditions using core flood testing apparatus. A series of core flood tests were conducted to examine the effectiveness and any formation damage of both relative permeability modifier chemistries at various concentrations under different saturation conditions. The RPM was applied into a brine saturated core – to assess its water "shut-off" properties and into an oil saturated core – to assess its formation damage potential. The effectiveness was assessed from comparing recovery permeability to water and oil. The data presented in this paper suggest that RPM B did not reduce the permeability to brine after application under the conditions and concentrations examined. RPM A on the other hand showed a clear potential to impair water permeability upon application, causing a dramatic rise in differential pressure and reduced brine permeability. At a concentration of ~ 5% for RPM A, the flow of brine was completely shut-off when applied to a water saturated core at residual oil and when applied to an oil saturated core at Swr, although the permeability to oil is reduced, oil production was still achievable. Reducing the concentration of the RPM A to 1% resulted in less shut-off than at 5%, indicating that the level of water control in the field can be optimised by altering the products concentration. This laboratory work indicates the effect of the chemicals on core samples, it does not address the placement of the chemicals in the field. This is critical to success once a suitably performing chemical has been identified in the laboratory. Placement design and suitability of treatment should therefore be considered for each indi
{"title":"Evaluation and Optimisation of Relative Permeability Modifiers for Water Control in Mature Wells","authors":"Ike Mokogwu, P. Hammonds, G. Graham","doi":"10.2118/208818-ms","DOIUrl":"https://doi.org/10.2118/208818-ms","url":null,"abstract":"\u0000 Water production from oil and gas wells increases lift costs and produces production problems such as effluent discharge limits, separation difficulties, fouling and corrosion. This is becoming more of a challenge in these times where the Carbon footprint of new oil and gas installations is under tighter environmental scrutiny. Therefore, prolonging the life of existing wells in an environmentally friendly and economic way is becoming increasingly important. As water production increases the profitability of a well typically decreases due to the costs incurred in dealing with the problems mentioned above. While several engineering solutions for curbing excessive water production exist, the cost of such solutions typically outweigh the benefits, hence favouring the use of chemicals. For chemicals to be successful, case by case evaluation is required. This paper examines the successful screening and evaluation of relative permeability modifiers for water control in the field.\u0000 Two relative permeability modifier chemicals (RPM A and RPM B) were selected for evaluation under simulated reservoir conditions. Prior to core flood testing, both chemicals were examined for stability and compatibility with formation fluids. While RPM B showed some signs of instability, ultimately, both chemicals were assessed under simulated reservoir conditions using core flood testing apparatus. A series of core flood tests were conducted to examine the effectiveness and any formation damage of both relative permeability modifier chemistries at various concentrations under different saturation conditions. The RPM was applied into a brine saturated core – to assess its water \"shut-off\" properties and into an oil saturated core – to assess its formation damage potential. The effectiveness was assessed from comparing recovery permeability to water and oil.\u0000 The data presented in this paper suggest that RPM B did not reduce the permeability to brine after application under the conditions and concentrations examined. RPM A on the other hand showed a clear potential to impair water permeability upon application, causing a dramatic rise in differential pressure and reduced brine permeability. At a concentration of ~ 5% for RPM A, the flow of brine was completely shut-off when applied to a water saturated core at residual oil and when applied to an oil saturated core at Swr, although the permeability to oil is reduced, oil production was still achievable. Reducing the concentration of the RPM A to 1% resulted in less shut-off than at 5%, indicating that the level of water control in the field can be optimised by altering the products concentration.\u0000 This laboratory work indicates the effect of the chemicals on core samples, it does not address the placement of the chemicals in the field. This is critical to success once a suitably performing chemical has been identified in the laboratory. Placement design and suitability of treatment should therefore be considered for each indi","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79491849","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}
Antonio A. Pontifes, Alexis Iwasiw, Eric Trevino, A. Mahmoudkhani
Recent developments in sampling and analytical techniques have enabled scientists to identify and track compositional changes in the molecular weights of paraffin hydrocarbons in organics rich shales wells towards higher molecular weight paraffin hydrocarbons. High molecular weight carbon chains (HMWCs) are generally regarded as the problematic hydrocarbons as they have the highest tendency to precipitate, deposit, and restrict flow in near wellbore zones, flowlines, valves, and chocks. This paper presents a systematic laboratory approach for monitoring and screening for of C60+paraffin waxes in shale oils and field deposits. A comprehensive validation methodology for benchmarking polymeric chemistries in laboratory for controlling and inhibiting C61 – C100 paraffin waxes is discussed based on the results from gas chromatography analysis (GC), differential scanning calorimetry analysis (DCS), X-ray diffraction analysis (XRD), and cold finger wax deposit testing. Modes of action of four polymeric chemistries are discussed based on laboratory data. Results showed none of the polymeric compounds performed as wax crystal modifiers for C60+paraffins, but more likely did disperse C60+wax crystals to some degree. This leads to the alarming conclusion that use of some paraffin inhibitors could lead to a much severe wax deposition when higher amounts of very large paraffin molecules are present in reservoir hydrocarbons. A plausible theory is proposed based on the "folded chain model" and common understanding of how polymeric inhibitors interact with paraffin wax molecules. It was found that model oil systems are more realistic for suitable to screening existing and new inhibitor chemistries for wax control and management when very high molecular weight paraffin molecules are present.
{"title":"A Comprehensive Validation Methodology for Benchmarking Polymeric Chemistries for Controlling and Inhibiting C60+ Paraffin Waxes in Shale Oils","authors":"Antonio A. Pontifes, Alexis Iwasiw, Eric Trevino, A. Mahmoudkhani","doi":"10.2118/208867-ms","DOIUrl":"https://doi.org/10.2118/208867-ms","url":null,"abstract":"\u0000 Recent developments in sampling and analytical techniques have enabled scientists to identify and track compositional changes in the molecular weights of paraffin hydrocarbons in organics rich shales wells towards higher molecular weight paraffin hydrocarbons. High molecular weight carbon chains (HMWCs) are generally regarded as the problematic hydrocarbons as they have the highest tendency to precipitate, deposit, and restrict flow in near wellbore zones, flowlines, valves, and chocks. This paper presents a systematic laboratory approach for monitoring and screening for of C60+paraffin waxes in shale oils and field deposits. A comprehensive validation methodology for benchmarking polymeric chemistries in laboratory for controlling and inhibiting C61 – C100 paraffin waxes is discussed based on the results from gas chromatography analysis (GC), differential scanning calorimetry analysis (DCS), X-ray diffraction analysis (XRD), and cold finger wax deposit testing. Modes of action of four polymeric chemistries are discussed based on laboratory data. Results showed none of the polymeric compounds performed as wax crystal modifiers for C60+paraffins, but more likely did disperse C60+wax crystals to some degree. This leads to the alarming conclusion that use of some paraffin inhibitors could lead to a much severe wax deposition when higher amounts of very large paraffin molecules are present in reservoir hydrocarbons. A plausible theory is proposed based on the \"folded chain model\" and common understanding of how polymeric inhibitors interact with paraffin wax molecules. It was found that model oil systems are more realistic for suitable to screening existing and new inhibitor chemistries for wax control and management when very high molecular weight paraffin molecules are present.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80460663","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}
Jorge Vazquez Morin, Francisco Landon, A. Flores, Antonio Manuel Garcia, Carmen Barrientos, Sergio Troncoso, Ivan Ernesto Narvaez, Jose Francisco Joya Ruiz, Andrea Murillo, K. Campos
An operator in Mexico was seeking a solution for improving methods for acid stimulation treatment in open-hole wells. Previous bullheading acid treatment in the same field was less efficient compared with selective treatment according to production conditions. In the shallow waters (offshore, Mexico), the acid stimulations are normally performed with bullheading technique; however, there are some cases where it is complicated to stimulate the production zone uniformly, especially in large openhole sections that presents fractures. Selective acid treatment technique is an alternative solution that represents an opportunity for the optimization of stimulations in Mexico and globally. The selected well has a 234 m open-hole section in a naturally fractured carbonate formation. Breaking usual paradigms, an unconventional treatment based on hydro-mechanical method for selective stimulation along the open hole was applied and completed with successful results. The operation was completed using coiled tubing (CT) deploying the Self-Aligning Jetting (SAJ) tool to stimulate 15 specific zones along the open hole section, each one selected for having the best petrophysical parameters. A 65% decrease in the acid treatment volume was obtained, which translates into savings in well flow back time, thus less Nitrogen to kick off the well, and removal time to the floating Storage/Production vessel (FSPV), in conclusion, oil production was incorporated more quickly after the well stimulation in comparison to the bullheading treatment. Comparing the two last open-hole stimulations in the same field, the productivity index obtained from conventional stimulation (bullheading) was in the order of 82 bpd/(kg/cm2), while selective stimulation was in the order of 160 bpd/(kg/cm), which is equivalent to an increase 95%. This paper presents the innovative technique of the stimulation with mechanical diversion using SAJ as the best option for injecting high-pressure fluids into specific targets through the open hole, and the advantages of the zones with the greatest oil production potential being stimulated, preventing the treatment from focusing only on a fractured zone or on areas with water or gas production potential.
{"title":"Enhancing Increased Production in an Open Hole Well by the Acid Stimulation Design Optimization using Self-Aligning-Jetting-Tool in Mexico Offshore","authors":"Jorge Vazquez Morin, Francisco Landon, A. Flores, Antonio Manuel Garcia, Carmen Barrientos, Sergio Troncoso, Ivan Ernesto Narvaez, Jose Francisco Joya Ruiz, Andrea Murillo, K. Campos","doi":"10.2118/208853-ms","DOIUrl":"https://doi.org/10.2118/208853-ms","url":null,"abstract":"\u0000 An operator in Mexico was seeking a solution for improving methods for acid stimulation treatment in open-hole wells. Previous bullheading acid treatment in the same field was less efficient compared with selective treatment according to production conditions. In the shallow waters (offshore, Mexico), the acid stimulations are normally performed with bullheading technique; however, there are some cases where it is complicated to stimulate the production zone uniformly, especially in large openhole sections that presents fractures.\u0000 Selective acid treatment technique is an alternative solution that represents an opportunity for the optimization of stimulations in Mexico and globally. The selected well has a 234 m open-hole section in a naturally fractured carbonate formation. Breaking usual paradigms, an unconventional treatment based on hydro-mechanical method for selective stimulation along the open hole was applied and completed with successful results. The operation was completed using coiled tubing (CT) deploying the Self-Aligning Jetting (SAJ) tool to stimulate 15 specific zones along the open hole section, each one selected for having the best petrophysical parameters.\u0000 A 65% decrease in the acid treatment volume was obtained, which translates into savings in well flow back time, thus less Nitrogen to kick off the well, and removal time to the floating Storage/Production vessel (FSPV), in conclusion, oil production was incorporated more quickly after the well stimulation in comparison to the bullheading treatment. Comparing the two last open-hole stimulations in the same field, the productivity index obtained from conventional stimulation (bullheading) was in the order of 82 bpd/(kg/cm2), while selective stimulation was in the order of 160 bpd/(kg/cm), which is equivalent to an increase 95%. This paper presents the innovative technique of the stimulation with mechanical diversion using SAJ as the best option for injecting high-pressure fluids into specific targets through the open hole, and the advantages of the zones with the greatest oil production potential being stimulated, preventing the treatment from focusing only on a fractured zone or on areas with water or gas production potential.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89478525","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}
Sam Wilson, P. Hammonds, G. Graham, D. Nichols, Hanen Ben Abdallah Bellio, F. Azuddin, Y. A. Sazali, A. Sauri
We report the development of a model to support matrix-based stimulation treatments in limestone reservoirs that takes information directly from data obtained during core flooding, such that the model can be calibrated against a variety of novel stimulation fluids under conditions directly representative of the candidate field. The model builds on an earlier stimulation model developed for clastic reservoirs, which primarily addressed stimulation as a formation-damage-removal phenomenon; it maintains the 3-dimensional aspects of the earlier model but incorporates the substantially greater complexity required in coupling the damage-dissolution reactions to the hydrodynamic phenomena associated with the formation of wormholes. Wormholes are an ideal method of stimulating carbonate reservoirs (in the absence of massive hydraulic fracturing) but their formation is stochastic, anisotropic, and involves greater morphological changes. Hence, successful stimulation depends on formulation chemistry, application rates, rock morphology, pressure, and temperature. This initial model has been calibrated to describe the behaviour of a selection of non-standard stimulation fluids, which have been evaluated in part through core-flood performance. The reaction-rate data for these novel fluids was abstracted from a series of core flood experiments with effluent and morphological analyses. The user interface provides easy condition input and selection and provides a clear output of results. Future developments will expand the model to a broader range of conditions and chemical formulations.
{"title":"Modelling of Stimulation Fluid Placement and Flow in Carbonate Reservoirs","authors":"Sam Wilson, P. Hammonds, G. Graham, D. Nichols, Hanen Ben Abdallah Bellio, F. Azuddin, Y. A. Sazali, A. Sauri","doi":"10.2118/208804-ms","DOIUrl":"https://doi.org/10.2118/208804-ms","url":null,"abstract":"\u0000 We report the development of a model to support matrix-based stimulation treatments in limestone reservoirs that takes information directly from data obtained during core flooding, such that the model can be calibrated against a variety of novel stimulation fluids under conditions directly representative of the candidate field. The model builds on an earlier stimulation model developed for clastic reservoirs, which primarily addressed stimulation as a formation-damage-removal phenomenon; it maintains the 3-dimensional aspects of the earlier model but incorporates the substantially greater complexity required in coupling the damage-dissolution reactions to the hydrodynamic phenomena associated with the formation of wormholes. Wormholes are an ideal method of stimulating carbonate reservoirs (in the absence of massive hydraulic fracturing) but their formation is stochastic, anisotropic, and involves greater morphological changes. Hence, successful stimulation depends on formulation chemistry, application rates, rock morphology, pressure, and temperature. This initial model has been calibrated to describe the behaviour of a selection of non-standard stimulation fluids, which have been evaluated in part through core-flood performance. The reaction-rate data for these novel fluids was abstracted from a series of core flood experiments with effluent and morphological analyses. The user interface provides easy condition input and selection and provides a clear output of results. Future developments will expand the model to a broader range of conditions and chemical formulations.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90763099","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}
Sand Control completions in long horizontal laterals often present challenging conditions because of a wide range of formation particle sizes and inflow rates which must be contained with a single completion. To aid in the screen selection process, laboratory testing of possible sand control media has proven to be a reliable method to improve the success of the completion. Soft sand completions are generally characterized into two classes of wellbore environments. A rapid wellbore collapse onto the screen or a gradual mechanical failure of the surrounding formation. Depending upon the type of wellbore environment encountered, one sand control test may provide a closer simulation to the failure phenomenon in the wellbore than another. This paper reviews three primary types of sand retention tests that include Constant Drawdown (pre-pack), Constant Rate, and Cyclical Brine. There are several variations on each test method, particularly the constant rate test method. The primary objective of any sand retention test method is to determine the amount and size of solids production through the sand control media with a specific particle size distribution. However, the various test methods provide additional performance data to aid in selecting a sand control system for a given environment. The Constant Drawdown method simulates a wellbore that is in conformance with the sand control media. This method provides retained screen permeability, as well as the formation and system permeabilities at multiple stress levels. Similarly, the Cyclical Brine method simulates a rapid wellbore collapse with an emphasis on injection well shut ins. This test provides system permeability data in both the injection and production flow directions. Lastly, the Constant Rate methods simulate a gradual or erosional failure of the wellbore on the sand control media. In these tests, a fluidized slurry contacts the sand control media in the open annulus, providing increasing pressure data with time. Using the sand retention data from these test methods a master curve is generated, which can predict how the screen will perform with various particle size distributions. A detailed analysis of particle size data down a lateral and interpretation with the Master Curves has been completed and provides a prediction of the performance of the sand retention media across the range of formation particle size distributions. By comparing the various evaluation methods through a reproducible sand retention study, we can optimize laboratory evaluation methods for a variety of wellbore environments. This provides the industry a comprehensive guide for matching wellbore specifications to the ideal laboratory sand retention evaluation method, optimizing the sand control selection to the well.
{"title":"A Comprehensive Review of Sand Retention Test Methods and Data Analysis with a Focus of Application","authors":"Tanner Linden, C. Fischer","doi":"10.2118/208845-ms","DOIUrl":"https://doi.org/10.2118/208845-ms","url":null,"abstract":"\u0000 Sand Control completions in long horizontal laterals often present challenging conditions because of a wide range of formation particle sizes and inflow rates which must be contained with a single completion. To aid in the screen selection process, laboratory testing of possible sand control media has proven to be a reliable method to improve the success of the completion.\u0000 Soft sand completions are generally characterized into two classes of wellbore environments. A rapid wellbore collapse onto the screen or a gradual mechanical failure of the surrounding formation. Depending upon the type of wellbore environment encountered, one sand control test may provide a closer simulation to the failure phenomenon in the wellbore than another.\u0000 This paper reviews three primary types of sand retention tests that include Constant Drawdown (pre-pack), Constant Rate, and Cyclical Brine. There are several variations on each test method, particularly the constant rate test method.\u0000 The primary objective of any sand retention test method is to determine the amount and size of solids production through the sand control media with a specific particle size distribution. However, the various test methods provide additional performance data to aid in selecting a sand control system for a given environment. The Constant Drawdown method simulates a wellbore that is in conformance with the sand control media. This method provides retained screen permeability, as well as the formation and system permeabilities at multiple stress levels. Similarly, the Cyclical Brine method simulates a rapid wellbore collapse with an emphasis on injection well shut ins. This test provides system permeability data in both the injection and production flow directions. Lastly, the Constant Rate methods simulate a gradual or erosional failure of the wellbore on the sand control media. In these tests, a fluidized slurry contacts the sand control media in the open annulus, providing increasing pressure data with time.\u0000 Using the sand retention data from these test methods a master curve is generated, which can predict how the screen will perform with various particle size distributions. A detailed analysis of particle size data down a lateral and interpretation with the Master Curves has been completed and provides a prediction of the performance of the sand retention media across the range of formation particle size distributions.\u0000 By comparing the various evaluation methods through a reproducible sand retention study, we can optimize laboratory evaluation methods for a variety of wellbore environments. This provides the industry a comprehensive guide for matching wellbore specifications to the ideal laboratory sand retention evaluation method, optimizing the sand control selection to the well.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"64 6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88223781","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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