Cementing is one of the most important steps in preparing a well for production. Critical parameters influencing the success of a cementing job are the concentration and the types of additives present in a mix fluid to prepare the cement slurry. However, it is extremely challenging to analyze water-soluble organics under oilfield operational conditions. In addition, with the complexity in chemistry of additives and mix fluids, it is also an analytical challenge to experimentally determine the quality of mix fluid and the slurry with standard analytical techniques such as high-pressure liquid chromatography (HPLC) or inductively coupled plasma spectroscopy (ICP). In addition to the general business need to verify chemical addition accuracy, in the field, the current practice to prepare mix fluid entails the addition of different additives either manually or using specialized liquid additive systems (LAS). Any human error in programming the LAS or manually adding the products yielding poor or no traceability for QA/QC could fail the cement job. This warrants the need for a reliable and field-robust method of quantifying additive concentrations in the mix fluid. To address this challenge, we developed a workflow using electrophoresis to address this issue to support operations. Electrophoresis uses an electric field to separate and quantify the components of a single fluid or a mix-fluid additive system. More importantly, we can simultaneously detect and quantify multiple chemistries in a single run. We have developed methods to analyze and quantify all the ingredients in an aqueous fluid system. This includes organics such as surfactants, natural and synthetic polymers, organic acid, and the inorganic ions that are common in seawater and most base fluids in the additive system. In the first step, we developed a method to analyze a single additive. This method addressed the issue of analyzing organics in aqueous fluid and demonstrated the applicability of this technology in determining the quality of the additives in terms of contamination. In later steps, the method was expanded to analyze and quantify dispersants, multicomponent retarders, and antifoaming agents individually as well together in a single run. Our study clearly demonstrated the electrophoresis technique can quantitatively differentiate multiple additives in a mix-fluid system while simultaneously estimating their respective ratios in the system. The developed method was applied to a mix-fluid system to identify a missing additive that led to the failure of a critical job. Overall, a simple and reliable technique is introduced to determine the quality and composition of additives and the mix-fluid system composition to enhance the reliability of existing processes and thereby improve the success rate of cementing jobs. Examples from the field will be presented.
{"title":"Improving Cementing Success with Better QC: Field Case Studies of using a World-First Quantifiable Mix-Water Analysis Technique","authors":"S. C. Mahavadi, Nathan Curtis, S. Taoutaou","doi":"10.2118/197405-ms","DOIUrl":"https://doi.org/10.2118/197405-ms","url":null,"abstract":"\u0000 Cementing is one of the most important steps in preparing a well for production. Critical parameters influencing the success of a cementing job are the concentration and the types of additives present in a mix fluid to prepare the cement slurry. However, it is extremely challenging to analyze water-soluble organics under oilfield operational conditions. In addition, with the complexity in chemistry of additives and mix fluids, it is also an analytical challenge to experimentally determine the quality of mix fluid and the slurry with standard analytical techniques such as high-pressure liquid chromatography (HPLC) or inductively coupled plasma spectroscopy (ICP). In addition to the general business need to verify chemical addition accuracy, in the field, the current practice to prepare mix fluid entails the addition of different additives either manually or using specialized liquid additive systems (LAS). Any human error in programming the LAS or manually adding the products yielding poor or no traceability for QA/QC could fail the cement job. This warrants the need for a reliable and field-robust method of quantifying additive concentrations in the mix fluid.\u0000 To address this challenge, we developed a workflow using electrophoresis to address this issue to support operations. Electrophoresis uses an electric field to separate and quantify the components of a single fluid or a mix-fluid additive system. More importantly, we can simultaneously detect and quantify multiple chemistries in a single run. We have developed methods to analyze and quantify all the ingredients in an aqueous fluid system. This includes organics such as surfactants, natural and synthetic polymers, organic acid, and the inorganic ions that are common in seawater and most base fluids in the additive system.\u0000 In the first step, we developed a method to analyze a single additive. This method addressed the issue of analyzing organics in aqueous fluid and demonstrated the applicability of this technology in determining the quality of the additives in terms of contamination. In later steps, the method was expanded to analyze and quantify dispersants, multicomponent retarders, and antifoaming agents individually as well together in a single run. Our study clearly demonstrated the electrophoresis technique can quantitatively differentiate multiple additives in a mix-fluid system while simultaneously estimating their respective ratios in the system. The developed method was applied to a mix-fluid system to identify a missing additive that led to the failure of a critical job.\u0000 Overall, a simple and reliable technique is introduced to determine the quality and composition of additives and the mix-fluid system composition to enhance the reliability of existing processes and thereby improve the success rate of cementing jobs. Examples from the field will be presented.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"494 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77338187","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}
Thanudcha Khunmek, I. Chigbo, Asaduwut Sreeroch, Feras Abu-Jafar
This paper will discuss completion design and the deployment method of sand control for multi-zone completion wells in the Nong Yao field. The discussion will cover sand control and completion techniques from given reservoir characteristics, in combination with the production strategy. Operational challenges from offset wells will be discussed. The Production strategy for the field required careful consideration for the unconsolidated nature of the reservoirs. An effective drawdown strategy is required as Electrical Submersible Pumps (ESPs) are deployed for artificial lift. The teams designed and implemented a cost effective multi-zone completion (MZC) with selectivity and sand control. The completion was designed to fit in a 7" 23# casing and is comprised of a lower and an upper completion. The complexity of the lower completion; 4" sand screen as outer string, internal 2-3/8" tubing with sliding side doors (SSDs), seal bores and packers, made deployment a challenge with a hydraulic workover unit due to the limitations of stroke length and gin pole. The completion equipment were selected based on workover operations pipe handling constraint, i.e. stroke length, gin poling hanging weight. As the workover stroke length is only 10 ft., R2 range screen and blank pipe was selected instead of the typical R3 range to prevent screen damage when passing through the stationary slip of the workover unit. Moreover, the total screen length combined with blank pipe has to be designed to meet the sand control objectives and stay within the gin pole hanging weight limitation. The lower completion was completed for selective production zone by zone, and was followed by an upper completion (Y-Tool and ESPs) to produce the hydrocarbons. The first well completed as a MZC with selective sand control has been on production for more than six months with no sand checking the base sediment and water (BS&W), even though the well has produced at high water cut and at relatively high rates. This observation shows that the implemented completion design along with production start-up strategy is working well. This same strategy is being applied in future wells.
{"title":"The First Application of a Novel Cased Hole Selective Multi-Zone Sand Control Completion in Gulf of Thailand","authors":"Thanudcha Khunmek, I. Chigbo, Asaduwut Sreeroch, Feras Abu-Jafar","doi":"10.2118/197351-ms","DOIUrl":"https://doi.org/10.2118/197351-ms","url":null,"abstract":"\u0000 This paper will discuss completion design and the deployment method of sand control for multi-zone completion wells in the Nong Yao field. The discussion will cover sand control and completion techniques from given reservoir characteristics, in combination with the production strategy. Operational challenges from offset wells will be discussed.\u0000 The Production strategy for the field required careful consideration for the unconsolidated nature of the reservoirs. An effective drawdown strategy is required as Electrical Submersible Pumps (ESPs) are deployed for artificial lift. The teams designed and implemented a cost effective multi-zone completion (MZC) with selectivity and sand control. The completion was designed to fit in a 7\" 23# casing and is comprised of a lower and an upper completion. The complexity of the lower completion; 4\" sand screen as outer string, internal 2-3/8\" tubing with sliding side doors (SSDs), seal bores and packers, made deployment a challenge with a hydraulic workover unit due to the limitations of stroke length and gin pole.\u0000 The completion equipment were selected based on workover operations pipe handling constraint, i.e. stroke length, gin poling hanging weight.\u0000 As the workover stroke length is only 10 ft., R2 range screen and blank pipe was selected instead of the typical R3 range to prevent screen damage when passing through the stationary slip of the workover unit. Moreover, the total screen length combined with blank pipe has to be designed to meet the sand control objectives and stay within the gin pole hanging weight limitation. The lower completion was completed for selective production zone by zone, and was followed by an upper completion (Y-Tool and ESPs) to produce the hydrocarbons.\u0000 The first well completed as a MZC with selective sand control has been on production for more than six months with no sand checking the base sediment and water (BS&W), even though the well has produced at high water cut and at relatively high rates. This observation shows that the implemented completion design along with production start-up strategy is working well. This same strategy is being applied in future wells.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88791389","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}
Pradeep Menon, A. Anurag, C. Mills, M. Basioni, S. Steiner, Mohammed AlBlooshi, Suvodip Dasgupta, J. Guerra, S. Shasmal, Israa Adil Suliman Salim
The Khuff Formation is a Permo-Triassic aged carbonate unit which reservoirs a highly economic gas resource in several countries within the Middle East. The appraisal and development of Khuff Formation tight gas resources is the subject of increased focus in the offshore UAE. This case study focuses on the appraisal of a particular field in offshore Abu Dhabi and summarizes how the understanding of this complex reservoir has evolved over time. The oldest well penetrating the Khuff Formation in this field was drilled almost 3 decades ago. This well tested gas within the Upper Khuff however appraisal of this resource had to wait until 2017-18 when two appraisal wells were drilled on the discovery. These appraisal wells included a complete suite of wireline logs, image log data, formation pressure measurements and well tests to give a clearer picture of the formation and fluid saturations. Subsequent to the drilling of the recent appraisal wells an integrated study was completed integrating all the processed and advanced answer products in order to determine the key elements controlling gas productivity. This knowledge were subsequently applied to optimise a well drilled and production tested in late 2018. Understanding the production behavior of the Khuff Formation reservoirs intervals has been one of the most critical factors behind the decision to develop this complex reservoir. Certain key answer products are considered critical for identification of completion intervals. These products include; sonic imaging (looking for fractures away from the wellbore), advanced textural analysis from borehole images (porosity classification) and critically stressed fracture analysis from geomechanics. This study led to the conclusion that critically stressed fractures and/or connected pores from images are the best indicators of high gas flow potential, while this flow can become exponentially higher when fractures at the wellbore connect to fractures away from the wellbore. This workflow has now been applied to the most recently drilled well and to other Khuff Formation appraisal projects across the off shore of Abu Dhabi. This is an illustration of how in-depth analysis of all the acquired data in an integrated manner can help in understanding a complex reservoir and lead to better decision-making for the future wells and offset appraisal projects. Lessons are hidden in both success and failure and as long as these lessons are analyzed properly, they can lead to long-term success.
{"title":"Evolution of Khuff Tight Gas Reservoir Understanding for a Field in Offshore Abu Dhabi","authors":"Pradeep Menon, A. Anurag, C. Mills, M. Basioni, S. Steiner, Mohammed AlBlooshi, Suvodip Dasgupta, J. Guerra, S. Shasmal, Israa Adil Suliman Salim","doi":"10.2118/197428-ms","DOIUrl":"https://doi.org/10.2118/197428-ms","url":null,"abstract":"\u0000 The Khuff Formation is a Permo-Triassic aged carbonate unit which reservoirs a highly economic gas resource in several countries within the Middle East. The appraisal and development of Khuff Formation tight gas resources is the subject of increased focus in the offshore UAE. This case study focuses on the appraisal of a particular field in offshore Abu Dhabi and summarizes how the understanding of this complex reservoir has evolved over time.\u0000 The oldest well penetrating the Khuff Formation in this field was drilled almost 3 decades ago. This well tested gas within the Upper Khuff however appraisal of this resource had to wait until 2017-18 when two appraisal wells were drilled on the discovery. These appraisal wells included a complete suite of wireline logs, image log data, formation pressure measurements and well tests to give a clearer picture of the formation and fluid saturations. Subsequent to the drilling of the recent appraisal wells an integrated study was completed integrating all the processed and advanced answer products in order to determine the key elements controlling gas productivity. This knowledge were subsequently applied to optimise a well drilled and production tested in late 2018.\u0000 Understanding the production behavior of the Khuff Formation reservoirs intervals has been one of the most critical factors behind the decision to develop this complex reservoir. Certain key answer products are considered critical for identification of completion intervals. These products include; sonic imaging (looking for fractures away from the wellbore), advanced textural analysis from borehole images (porosity classification) and critically stressed fracture analysis from geomechanics. This study led to the conclusion that critically stressed fractures and/or connected pores from images are the best indicators of high gas flow potential, while this flow can become exponentially higher when fractures at the wellbore connect to fractures away from the wellbore. This workflow has now been applied to the most recently drilled well and to other Khuff Formation appraisal projects across the off shore of Abu Dhabi.\u0000 This is an illustration of how in-depth analysis of all the acquired data in an integrated manner can help in understanding a complex reservoir and lead to better decision-making for the future wells and offset appraisal projects. Lessons are hidden in both success and failure and as long as these lessons are analyzed properly, they can lead to long-term success.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"1986 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90332395","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}
M. B. Geri, R. Flori, Abdulaziz Ellafi, J. Noles, J. Essman, Sangjoon Kim, Ethar H. K. Alkamil
Hydraulic fracturing operation requires securing sufficient water resources to access unlocked formations. Successful treatment depends on the fracture fluids that mainly consists of water-based fluid with a low percentage of chemical additives around 1%. Therefore, the oil and gas industry are considered as the largest freshwater consumers by 3 to 6 million gallons of water per well based on a number of fracturing stages. As a result, the traditional water resources from subsurface and surface are getting depleted, and availability of freshwater is becoming more difficult with high cost due to continued demand. For example, operator companies in West Texas face many challenges, including a recent increase from USD 3 to 10 per m3 of freshwater. In addition, transporting process of the raw water to the fracture sites, such as Bakken has an environmental impact, and expensive costs up to USD 5/bbl, while costs of water disposal in range of USD 9/bbl. This paper aims to study the produced water as alternative water-based fluid with high viscosity friction reducers (HVFR) to reduce environmental footprints and economic costs. To address utilizing produced water as an alternative capable water resource that may use during fracturing treatment, this research presents an experimental investigation associated with using the Permian high-TDS brine water with HVFRs. This work includes experimental research, case studies, and guidelines work on recent improvements on using HVFR to carry proppant and capture the optimum design in fracturing operations. Moreover, the research conducted scaled lab friction measurements that can in turn to be used to improve forecasting of frictions in the field, and therefore of expected surface treating pressures during fracture treatments. Evaluating pipe friction as a function of time to compare HVFRs efficacy in lab and field conditions as well as to predict maximum injection rate during a frac job is investigated. The outcomes show that high-TDS Permian water with highest dosage of HVFRs had instantaneous pressure reduction effect in 10 seconds while low dosage of HVFRs had lost the effect slowly after 4 min. 30 sec. Also, the results of this study show that the variation of viscosity and pressure reduction at higher shear rate is small. The warm temperature helped rapid polymer dispersion and provided better environment to polymer hydration leads to rapid pressure reduction. Finally, successful implementation in Wlofcamp formation shows that the operation treating pressure reduced from 11,000 to 8,000 psi. The general guidelines obtained can promote the sustainability of using hydraulic fracturing treatment to produce more oil and gas from unconventional resources without considering environmental issues.
{"title":"Correlated Friction Reduction and Viscoelastic Characterization of Utilizing the Permian Produced Water with HVFRs during Hydraulic Fracturing","authors":"M. B. Geri, R. Flori, Abdulaziz Ellafi, J. Noles, J. Essman, Sangjoon Kim, Ethar H. K. Alkamil","doi":"10.2118/197748-ms","DOIUrl":"https://doi.org/10.2118/197748-ms","url":null,"abstract":"\u0000 Hydraulic fracturing operation requires securing sufficient water resources to access unlocked formations. Successful treatment depends on the fracture fluids that mainly consists of water-based fluid with a low percentage of chemical additives around 1%. Therefore, the oil and gas industry are considered as the largest freshwater consumers by 3 to 6 million gallons of water per well based on a number of fracturing stages. As a result, the traditional water resources from subsurface and surface are getting depleted, and availability of freshwater is becoming more difficult with high cost due to continued demand. For example, operator companies in West Texas face many challenges, including a recent increase from USD 3 to 10 per m3 of freshwater. In addition, transporting process of the raw water to the fracture sites, such as Bakken has an environmental impact, and expensive costs up to USD 5/bbl, while costs of water disposal in range of USD 9/bbl.\u0000 This paper aims to study the produced water as alternative water-based fluid with high viscosity friction reducers (HVFR) to reduce environmental footprints and economic costs. To address utilizing produced water as an alternative capable water resource that may use during fracturing treatment, this research presents an experimental investigation associated with using the Permian high-TDS brine water with HVFRs. This work includes experimental research, case studies, and guidelines work on recent improvements on using HVFR to carry proppant and capture the optimum design in fracturing operations. Moreover, the research conducted scaled lab friction measurements that can in turn to be used to improve forecasting of frictions in the field, and therefore of expected surface treating pressures during fracture treatments. Evaluating pipe friction as a function of time to compare HVFRs efficacy in lab and field conditions as well as to predict maximum injection rate during a frac job is investigated.\u0000 The outcomes show that high-TDS Permian water with highest dosage of HVFRs had instantaneous pressure reduction effect in 10 seconds while low dosage of HVFRs had lost the effect slowly after 4 min. 30 sec. Also, the results of this study show that the variation of viscosity and pressure reduction at higher shear rate is small. The warm temperature helped rapid polymer dispersion and provided better environment to polymer hydration leads to rapid pressure reduction. Finally, successful implementation in Wlofcamp formation shows that the operation treating pressure reduced from 11,000 to 8,000 psi. The general guidelines obtained can promote the sustainability of using hydraulic fracturing treatment to produce more oil and gas from unconventional resources without considering environmental issues.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82526956","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}
Many application and operational methods have been developed for applying carbonate matrix acidizing to successfully stimulate heterogeneous and long horizontal openhole zones. These methods have also been implemented during acid fracturing to various degrees of success. This paper discusses in detail the laboratory assessment of a biodegradable material for acid diversion in highly fractured formations. Diversion in fracture acidizing is extremely challenging because of the high pumping rate, extreme pressures, and larger volumes of acid compared to matrix acidizing. To effectively stimulate natural or pre-existing fractured formations, the diverting agent should be able to bridge not only at the perforations, but inside the fracture system, too. Historically, several methods have been implemented for acid-fracturing diversion, such as ball sealers, viscous fluids, packers, etc., resulting in limited success in formations with natural or pre-existing fractures. This paper discusses the use of an acid diverter that consists of biodegradable particles with different sizes and hardness. The particle size ratios are specifically designed where large particles will bridge in the fractures while the smaller particles "nest" in the pore throat of the bridged larger particles. This leads to quick, efficient blockage of fractures and acid diversion. The laboratory assessment of this biodegradable material was conducted at various temperatures up to 300°F and consists of (1) degradation in 3% KCl, live 15 wt% HCl, and spent 15% HCl, and (2) fluid loss using slotted disks at different diverter concentrations. The fractures were mimicked in the laboratory using a stainless steel slotted disk in a high-pressure/high-temperature (HP/HT) cell. The dissolution rate of the particles was observed to be a function of time and temperature. The dissolution rate of the diverter was higher in water as compared to 15 wt% HCl acid. The stability of the biodegradable diverter was conducted at 300°F. The filter cake was stable up to 30 minutes when 1.0 ppt of the biodegradable diverter was used. The results of this study indicate that the biodegradable diversion material can be used as an effective alternative diversion method to seal natural or pre-existing fractures.
{"title":"Assessment of Biodegradable Diverter for Acid Fracturing of Highly Fractured Formations","authors":"Ibrahim Al-Hulail, L. Eoff, Mashhoor Anazi","doi":"10.2118/197687-ms","DOIUrl":"https://doi.org/10.2118/197687-ms","url":null,"abstract":"\u0000 Many application and operational methods have been developed for applying carbonate matrix acidizing to successfully stimulate heterogeneous and long horizontal openhole zones. These methods have also been implemented during acid fracturing to various degrees of success. This paper discusses in detail the laboratory assessment of a biodegradable material for acid diversion in highly fractured formations.\u0000 Diversion in fracture acidizing is extremely challenging because of the high pumping rate, extreme pressures, and larger volumes of acid compared to matrix acidizing. To effectively stimulate natural or pre-existing fractured formations, the diverting agent should be able to bridge not only at the perforations, but inside the fracture system, too. Historically, several methods have been implemented for acid-fracturing diversion, such as ball sealers, viscous fluids, packers, etc., resulting in limited success in formations with natural or pre-existing fractures. This paper discusses the use of an acid diverter that consists of biodegradable particles with different sizes and hardness. The particle size ratios are specifically designed where large particles will bridge in the fractures while the smaller particles \"nest\" in the pore throat of the bridged larger particles. This leads to quick, efficient blockage of fractures and acid diversion.\u0000 The laboratory assessment of this biodegradable material was conducted at various temperatures up to 300°F and consists of (1) degradation in 3% KCl, live 15 wt% HCl, and spent 15% HCl, and (2) fluid loss using slotted disks at different diverter concentrations. The fractures were mimicked in the laboratory using a stainless steel slotted disk in a high-pressure/high-temperature (HP/HT) cell.\u0000 The dissolution rate of the particles was observed to be a function of time and temperature. The dissolution rate of the diverter was higher in water as compared to 15 wt% HCl acid. The stability of the biodegradable diverter was conducted at 300°F. The filter cake was stable up to 30 minutes when 1.0 ppt of the biodegradable diverter was used.\u0000 The results of this study indicate that the biodegradable diversion material can be used as an effective alternative diversion method to seal natural or pre-existing fractures.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74176408","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 a method to calculate an equivalent production rate and time (tp), that models the transient effect of a multirate production period prior to a buildup test. The proposed solution increases the accuracy of Pressure Transient Analysis (PTA). The traditional Horner method estimates the production time (tp) using the cumulative production and the last production rate; however, this method is an intuitive but not rigorous solution that puts emphasis on the most recent nonzero production rate. There are currently commercial applications that consider the superposition effects of complex production history for PTA analysis, nevertheless, superposition can include a material balance error. The proposed technique is an alternative to superposition that uses the transient effect generated for each production period to estimate the equivalent rate and production time. A reservoir simulation model with known petrophysical parameters, fluid properties, pressure, and temperature, is used as a reference to evaluate the accuracy of the proposed method. The studied reservoir produces through a well that uses a multirate schedule that includes two different scenarios: (1) a progressive increase in each new production rate and (2) a progressive decrease in each new production rate. Then, the well is shut-in, starting a buildup pressure response. Production time and rate are estimated by applying the Horner's approximation and the proposed solution. Finally, the results from both methods are compared with the known parameters of the reference model. The proposed method provides a more accurate solution to buildup analysis compared to the Horner time approximation by using the production rate history. The approach can also be applied to drawdown analysis and pressure derivative analysis, keeping the precision of the calculations.
{"title":"Alternative Method to Horner's Approximation for Multirate Analysis of Pressure Buildup","authors":"M. Useche, F. Franco","doi":"10.2118/197233-ms","DOIUrl":"https://doi.org/10.2118/197233-ms","url":null,"abstract":"\u0000 This paper presents a method to calculate an equivalent production rate and time (tp), that models the transient effect of a multirate production period prior to a buildup test. The proposed solution increases the accuracy of Pressure Transient Analysis (PTA).\u0000 The traditional Horner method estimates the production time (tp) using the cumulative production and the last production rate; however, this method is an intuitive but not rigorous solution that puts emphasis on the most recent nonzero production rate. There are currently commercial applications that consider the superposition effects of complex production history for PTA analysis, nevertheless, superposition can include a material balance error. The proposed technique is an alternative to superposition that uses the transient effect generated for each production period to estimate the equivalent rate and production time.\u0000 A reservoir simulation model with known petrophysical parameters, fluid properties, pressure, and temperature, is used as a reference to evaluate the accuracy of the proposed method. The studied reservoir produces through a well that uses a multirate schedule that includes two different scenarios: (1) a progressive increase in each new production rate and (2) a progressive decrease in each new production rate. Then, the well is shut-in, starting a buildup pressure response. Production time and rate are estimated by applying the Horner's approximation and the proposed solution. Finally, the results from both methods are compared with the known parameters of the reference model.\u0000 The proposed method provides a more accurate solution to buildup analysis compared to the Horner time approximation by using the production rate history. The approach can also be applied to drawdown analysis and pressure derivative analysis, keeping the precision of the calculations.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"59 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90582382","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}
Currently, the oil industry is using hydraulic fracture as a tool to exploit tight and ultra-tight oil formations. In carbonates, acid fracturing is common, unlike proppant fracturing in sandsones. The main objective of this paper is to study the behaviour of HCl injected and oil flow back from a horizontal well with multi-stage acid fractures (fractured hydraulically). For a vertical well, a single acid fracture is common. The 2D fracture model and psedo-3D fracture model are incorporated in this integrated program for acid fracturing with all geomechanics and operational constraints. With five stages of fractures, post-fracture oil production from an acid fractured horizontal/vertical well is generated from this integrated model. Program is written in MATHCAD to observe the volumetric flow rate in steady-state, transient, and pseudosteady regime. ANSYS Fluent is used to carry out a computational fluid dynamics (CFD) for oil flow back along the fractures. CFD is applied to observe production rates where sequential pad fluid and acid injection is performed until the desired fracture dimensions are reached. Results from production model shows, for steady-state, production increased from 44 to 60 STB/D and from 113 to 124 STB/D with P-3D-C and 2D-PKN-C fracture model respectively. CFD simulation is performed using a viscous model with gravitational and turbulent effects and the results show an increase in radial turbulence at the outlet of the fracture. The absolute pressure exerted on the walls is 1700 psi and the flow velocity increased from the tip at 39.4 ft/min covering a fracture length of 500 ft in both steady-state and transient flow. This paper investigates the effect of acid fracturing on oil production using a predetermined fracture model and dimensions. The flow characteristics are challenged in multi-stage fractures in horizontal and vertical well. The outcome of CFD will assist in upscaling the simulation to a 3D model with field values from existing wells for validity. A further development with fracture simulation are carried out for vertical and horizontal fracture to understand the deformation behavior on the predetermined zone. This paper will contribute to advanced well stimulation techniques of acid fracturing that are representative of actual field applications.
{"title":"Computational Fluid Dynamics of HCl Single and Two-Phase Oil Flow in a Multi-Stage Vertical and Horizontal Acid Fractured Well","authors":"Talal Al Hajeri, Motiur Rahman","doi":"10.2118/197662-ms","DOIUrl":"https://doi.org/10.2118/197662-ms","url":null,"abstract":"\u0000 Currently, the oil industry is using hydraulic fracture as a tool to exploit tight and ultra-tight oil formations. In carbonates, acid fracturing is common, unlike proppant fracturing in sandsones. The main objective of this paper is to study the behaviour of HCl injected and oil flow back from a horizontal well with multi-stage acid fractures (fractured hydraulically). For a vertical well, a single acid fracture is common.\u0000 The 2D fracture model and psedo-3D fracture model are incorporated in this integrated program for acid fracturing with all geomechanics and operational constraints. With five stages of fractures, post-fracture oil production from an acid fractured horizontal/vertical well is generated from this integrated model. Program is written in MATHCAD to observe the volumetric flow rate in steady-state, transient, and pseudosteady regime. ANSYS Fluent is used to carry out a computational fluid dynamics (CFD) for oil flow back along the fractures. CFD is applied to observe production rates where sequential pad fluid and acid injection is performed until the desired fracture dimensions are reached.\u0000 Results from production model shows, for steady-state, production increased from 44 to 60 STB/D and from 113 to 124 STB/D with P-3D-C and 2D-PKN-C fracture model respectively. CFD simulation is performed using a viscous model with gravitational and turbulent effects and the results show an increase in radial turbulence at the outlet of the fracture. The absolute pressure exerted on the walls is 1700 psi and the flow velocity increased from the tip at 39.4 ft/min covering a fracture length of 500 ft in both steady-state and transient flow.\u0000 This paper investigates the effect of acid fracturing on oil production using a predetermined fracture model and dimensions. The flow characteristics are challenged in multi-stage fractures in horizontal and vertical well. The outcome of CFD will assist in upscaling the simulation to a 3D model with field values from existing wells for validity. A further development with fracture simulation are carried out for vertical and horizontal fracture to understand the deformation behavior on the predetermined zone. This paper will contribute to advanced well stimulation techniques of acid fracturing that are representative of actual field applications.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76664358","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. Hussein, M. Alqassab, Hazem Atef, Siddesh Sirdhar, Salem Al-Ajmi, Khaled Waleed Aldeyain, M. F. Hassan, H. K. Goel
Umm Gudair (UG) field is one of the major oil fields of West Kuwait asset. Wells are tested periodically using multiple conventional test separators and data is subsequently used to update Well Performance "Nodal analysis" and "Live Flow Line Surface Network Model". A different approach was tested in 2018 for a mature oil field in the Middle East to evaluate the effectiveness of Clamp-On based SONAR Flow Surveillance solution against existing conventional portable test separator. The objective was to check the performance of the SONAR Flow Surveillance on black oil wells at different flowing conditions, and ultimately implement a new approach to increase the testing frequency, reduce any potential of hydrocarbon release, avoid well shutdown, optimize operating costs, and production optimization. The SONAR Surveillance approach is based on SONAR clamp-on flow meters deployed in conjunction with compositional (PVT) and multiphase flow models for oil and gas wells to interpret the measurements of the SONAR flow meters at line conditions (pressure, temperature, fluid stream composition), and output the gas, oil and water phase flow rates at both actual and standard conditions. The SONAR meter measures the bulk flow velocity (at line conditions), then a flow computer determines the individual phase volume fractions at actual conditions using a PVT model and water-cut. This provides a measure of the oil rate at actual conditions. A shrinkage factor calculated by the black oil model is applied to report oil rate at standard conditions. Gas and water are also inferred in a similar manner. The gas, oil and water flow rates thus determined at actual conditions are further processed and converted to standard conditions as well. The field tests showed that the SONAR Flow Surveillance approach allowed more flexibility in terms of field installation and the measurements are made at actual production conditions unlike other devices that may introduce additional flow restrictions. The SONAR meters diagnostics also provided a more realistic representation of the well flow profile since the measurements are instantaneous versus the "averaging" effects observed when using gravity-based separators. This allows better production surveillance and understanding of changes in well behavior.
{"title":"Mature Oilfield Production Surveillance and Optimization Using Clamp-On Sonarflow Surveillance","authors":"A. Hussein, M. Alqassab, Hazem Atef, Siddesh Sirdhar, Salem Al-Ajmi, Khaled Waleed Aldeyain, M. F. Hassan, H. K. Goel","doi":"10.2118/197543-ms","DOIUrl":"https://doi.org/10.2118/197543-ms","url":null,"abstract":"\u0000 Umm Gudair (UG) field is one of the major oil fields of West Kuwait asset. Wells are tested periodically using multiple conventional test separators and data is subsequently used to update Well Performance \"Nodal analysis\" and \"Live Flow Line Surface Network Model\".\u0000 A different approach was tested in 2018 for a mature oil field in the Middle East to evaluate the effectiveness of Clamp-On based SONAR Flow Surveillance solution against existing conventional portable test separator. The objective was to check the performance of the SONAR Flow Surveillance on black oil wells at different flowing conditions, and ultimately implement a new approach to increase the testing frequency, reduce any potential of hydrocarbon release, avoid well shutdown, optimize operating costs, and production optimization.\u0000 The SONAR Surveillance approach is based on SONAR clamp-on flow meters deployed in conjunction with compositional (PVT) and multiphase flow models for oil and gas wells to interpret the measurements of the SONAR flow meters at line conditions (pressure, temperature, fluid stream composition), and output the gas, oil and water phase flow rates at both actual and standard conditions. The SONAR meter measures the bulk flow velocity (at line conditions), then a flow computer determines the individual phase volume fractions at actual conditions using a PVT model and water-cut. This provides a measure of the oil rate at actual conditions. A shrinkage factor calculated by the black oil model is applied to report oil rate at standard conditions. Gas and water are also inferred in a similar manner. The gas, oil and water flow rates thus determined at actual conditions are further processed and converted to standard conditions as well.\u0000 The field tests showed that the SONAR Flow Surveillance approach allowed more flexibility in terms of field installation and the measurements are made at actual production conditions unlike other devices that may introduce additional flow restrictions. The SONAR meters diagnostics also provided a more realistic representation of the well flow profile since the measurements are instantaneous versus the \"averaging\" effects observed when using gravity-based separators. This allows better production surveillance and understanding of changes in well behavior.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78854472","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}
Andrea C. Knoerich, A. Dhahli, Sonia Lai, Sumaiya Habsi, S. Farsi
The Khuff formation in the Yibal field is currently undergoing one of the largest field development campaigns in PDO. While the main project driver is securing gas production (highly sour) at a stable plateau rate, maximizing oil rim recovery and production is the main objective of the presented study. This is challenging as all wells are pre-drilled as per FDP recommendation and any later development optimization is expected to be difficult and costly. Newly available static (seismic, well log, borehole images) and dynamic (well test) data were utilized in a decision driven modelling approach to update existing static and dynamic models to confirm the robustness of subsurface development decisions, oil production promises and EUR. Updated structural and property modeling results were utilized to optimize placement of 2/3 of the remaining wells in order to improve drainage. Reservoir rock typing and fracture interpretation, along with cased-hole surveillance data acquired in all wells, were used to optimize production intervals and to confirm the productivity of the different intervals (dolostone/ limestone/ fractures); which were then integrated to confirm the perforation strategy going forward. This study describes the first development of Khuff carbonates in Sultanate of Oman, with limited historical production data and no analogues in Sultanate of Oman. The study highlights the importance of continuous integration of new data in a decision driven modelling approach to ensure robustness of project decisions with timely project adjustments to prevent NPV erosion.
{"title":"Optimizing Oil Rim Development in a Tight, Fractured Carbonate Field: Khuff Formation, Yibal Field, Sultanate of Oman","authors":"Andrea C. Knoerich, A. Dhahli, Sonia Lai, Sumaiya Habsi, S. Farsi","doi":"10.2118/197303-ms","DOIUrl":"https://doi.org/10.2118/197303-ms","url":null,"abstract":"\u0000 The Khuff formation in the Yibal field is currently undergoing one of the largest field development campaigns in PDO. While the main project driver is securing gas production (highly sour) at a stable plateau rate, maximizing oil rim recovery and production is the main objective of the presented study. This is challenging as all wells are pre-drilled as per FDP recommendation and any later development optimization is expected to be difficult and costly.\u0000 Newly available static (seismic, well log, borehole images) and dynamic (well test) data were utilized in a decision driven modelling approach to update existing static and dynamic models to confirm the robustness of subsurface development decisions, oil production promises and EUR. Updated structural and property modeling results were utilized to optimize placement of 2/3 of the remaining wells in order to improve drainage. Reservoir rock typing and fracture interpretation, along with cased-hole surveillance data acquired in all wells, were used to optimize production intervals and to confirm the productivity of the different intervals (dolostone/ limestone/ fractures); which were then integrated to confirm the perforation strategy going forward.\u0000 This study describes the first development of Khuff carbonates in Sultanate of Oman, with limited historical production data and no analogues in Sultanate of Oman. The study highlights the importance of continuous integration of new data in a decision driven modelling approach to ensure robustness of project decisions with timely project adjustments to prevent NPV erosion.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74106121","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 technical presentation features various challenges that a turbomachinery OEM and the end users face with compressor trains in Ethylene Process, from the initial design phase, to the plant commissioning and operation of these machines. The presentation illustrates also the possible technical solutions, such as special coatings to prevent fouling in charge gas compressors, to help end users to reduce the operating cost and risk of production loss. The implementation of compact solutions, which helps the charge gas and ethylene compressors to deliver a higher-pressure ratio in one casing, results in lower number of bodies with same compression sections and consequently simplified installation and lower costs. Technical and special design features will be illustrated during the presentation. A smoother operation of the units can be offered building a dynamic model capable to simulate the behavior of the drivers, compressors and process plant items, in stable operating conditions and transient phases. With such model, any potential criticality of the interactions between process and compressors can be identified up-front in a simulation environment, minimizing risks at site, during commissioning and first start-up. The impact of fouling on ethylene plant equipment can be substantial. The high possibility of gas polymerization occurring in the cracked gas compressor can lead to efficiency loss and unplanned outages with associated lack of production. An advanced stage-by-stage water injection system coupled with fully removable nozzles during compressor operation and an efficiency monitoring and control system, will reduce operating cost and risk of production loss by providing operators with continuously updated equipment performance. This information can also be integrated with the analytic that performs an early detection of steam turbine fouling phenomena. Finally, the authors present few case studies where the above strategies were successfully implemented.
{"title":"Challenges of Ethylene Process Compressor Trains: From Design to Start-Up and Operability","authors":"S. Corbò, Mirco Calosi, Gianni Acquisti","doi":"10.2118/197563-ms","DOIUrl":"https://doi.org/10.2118/197563-ms","url":null,"abstract":"\u0000 This technical presentation features various challenges that a turbomachinery OEM and the end users face with compressor trains in Ethylene Process, from the initial design phase, to the plant commissioning and operation of these machines.\u0000 The presentation illustrates also the possible technical solutions, such as special coatings to prevent fouling in charge gas compressors, to help end users to reduce the operating cost and risk of production loss. The implementation of compact solutions, which helps the charge gas and ethylene compressors to deliver a higher-pressure ratio in one casing, results in lower number of bodies with same compression sections and consequently simplified installation and lower costs. Technical and special design features will be illustrated during the presentation.\u0000 A smoother operation of the units can be offered building a dynamic model capable to simulate the behavior of the drivers, compressors and process plant items, in stable operating conditions and transient phases. With such model, any potential criticality of the interactions between process and compressors can be identified up-front in a simulation environment, minimizing risks at site, during commissioning and first start-up.\u0000 The impact of fouling on ethylene plant equipment can be substantial. The high possibility of gas polymerization occurring in the cracked gas compressor can lead to efficiency loss and unplanned outages with associated lack of production. An advanced stage-by-stage water injection system coupled with fully removable nozzles during compressor operation and an efficiency monitoring and control system, will reduce operating cost and risk of production loss by providing operators with continuously updated equipment performance. This information can also be integrated with the analytic that performs an early detection of steam turbine fouling phenomena.\u0000 Finally, the authors present few case studies where the above strategies were successfully implemented.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78947999","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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