Nasser M. Al-Hajri, Abdullah A. Al-Ghamdi, Zeeshan Tariq, M. Mahmoud
This paper presents a data-driven methodology to predict calcium carbonate (CaCO3)-scale formation and design its inhibition program in petroleum wells. The proposed methodology integrates and adds to the existing principles of production surveillance, chemistry, machine learning (ML), and probability theory in a comprehensive decision workflow to achieve its purpose. The proposed model was applied on a large and representative field sample to verify its results. The method starts by collecting data such as ionic composition, pH, sample-collection/inspection dates, and scale-formation event. Then, collected data are classified or grouped according to production conditions. Calculation of chemical-scale indices is then made using techniques such as water-saturation level, Langelier saturation index (LSI), Ryznar saturation index (RSI), and Puckorius scaling index (PSI). The ML part of the method starts by dividing the data into training and test sets (80 and 20%, respectively). Classification models such as support-vector machine (SVM), K-nearest neighbors (KNN), gradient boosting, gradient-boosting classifier, and decision-tree classifier are all applied on collected data. Prediction results are then classified into a confusion matrix to be used as inputs for the probabilistic inhibition-design model. Finally, a functional-network (FN) tool is used to predict the formation of scale. The scale-inhibition program design uses a probabilistic model that quantifies the uncertainty associated with each ML method. The scale-prediction capability compared with actual inspection is presented into probability equations that are used in the cost model. The expected financial impact associated with applying any of the ML methods is obtained from defining costs for scale removal and scale inhibition. These costs are factored into the probability equations in a manner that presents incurred costs and saved or avoided expenses expected from field application of any given ML model. The forecasted cost model is built on a base-case method (i.e., current situation) to be used as a benchmark and foundation for the new scale-inhibition program. As will be presented in the paper, the results of applying the preceding techniques resulted in a scale-prediction accuracy of 95% and realized threefold cost-savings figures compared with existing programs.
{"title":"Scale-Prediction/Inhibition Design Using Machine-Learning Techniques and Probabilistic Approach","authors":"Nasser M. Al-Hajri, Abdullah A. Al-Ghamdi, Zeeshan Tariq, M. Mahmoud","doi":"10.2118/198646-pa","DOIUrl":"https://doi.org/10.2118/198646-pa","url":null,"abstract":"\u0000 This paper presents a data-driven methodology to predict calcium carbonate (CaCO3)-scale formation and design its inhibition program in petroleum wells. The proposed methodology integrates and adds to the existing principles of production surveillance, chemistry, machine learning (ML), and probability theory in a comprehensive decision workflow to achieve its purpose. The proposed model was applied on a large and representative field sample to verify its results.\u0000 The method starts by collecting data such as ionic composition, pH, sample-collection/inspection dates, and scale-formation event. Then, collected data are classified or grouped according to production conditions. Calculation of chemical-scale indices is then made using techniques such as water-saturation level, Langelier saturation index (LSI), Ryznar saturation index (RSI), and Puckorius scaling index (PSI). The ML part of the method starts by dividing the data into training and test sets (80 and 20%, respectively). Classification models such as support-vector machine (SVM), K-nearest neighbors (KNN), gradient boosting, gradient-boosting classifier, and decision-tree classifier are all applied on collected data. Prediction results are then classified into a confusion matrix to be used as inputs for the probabilistic inhibition-design model. Finally, a functional-network (FN) tool is used to predict the formation of scale.\u0000 The scale-inhibition program design uses a probabilistic model that quantifies the uncertainty associated with each ML method. The scale-prediction capability compared with actual inspection is presented into probability equations that are used in the cost model. The expected financial impact associated with applying any of the ML methods is obtained from defining costs for scale removal and scale inhibition. These costs are factored into the probability equations in a manner that presents incurred costs and saved or avoided expenses expected from field application of any given ML model. The forecasted cost model is built on a base-case method (i.e., current situation) to be used as a benchmark and foundation for the new scale-inhibition program.\u0000 As will be presented in the paper, the results of applying the preceding techniques resulted in a scale-prediction accuracy of 95% and realized threefold cost-savings figures compared with existing programs.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"35 1","pages":"0987-1009"},"PeriodicalIF":1.2,"publicationDate":"2020-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/198646-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46644999","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Sucker rod pumps provide a cost-efficient way to produce hydrocarbons from low-pressure reservoir formations. Their design is dependent on predictive models used to optimize the system before implementation in the field. The greater the accuracy of these models, the better the performance of the pumping system in the field. The scope of this paper is to present an improved plunger slippage model, developed in connection to the pump test facility (PTF) and validated by field data. This paper provides an analysis of plunger slippage. Existing plunger-slippage models are compared with field data. Based on the result of this comparison, an improved plunger-slippage model is derived based on the Navier-Stokes equation and dimensional analysis. Adjustments are applied to increase the model's validity. The mathematical and laboratory work have shown that a proper fit to reality requires four coefficients that make the equation an empirical one. An extensive laboratory test campaign, using real field equipment, was performed at the PTF at Montanuniversitaet Leoben (MUL). Numerous influencing parameters, such as plunger velocity, clearance magnitude, and fluid viscosity, were studied. Historical plunger-slippage models overestimate the slippage rate, whereas field data showed that newer models underestimate the slippage rate. In general, dynamic models are more accurate than static slippage models. The fit of the four model coefficients, based on laboratory tests, indicate that the chosen strategy of using laboratory tests and allocating the results to field conditions has worked out. The comparison of the results obtained by the presented improved slippage model and the field tests indicate a good match. The presented slippage model predicts the plunger slippage rate precisely and results in greater accuracy. The plunger wear rate approach is presented, which can be used to plan well interventions, decrease intervention costs, and increase the mean time between failures.
{"title":"Improved Slippage Model for Sucker Rod Pumps Developed in a Pump Test Facility and Verified by Field Measurements","authors":"C. Langbauer, D. Kochtik, L. Volker","doi":"10.2118/202474-pa","DOIUrl":"https://doi.org/10.2118/202474-pa","url":null,"abstract":"\u0000 Sucker rod pumps provide a cost-efficient way to produce hydrocarbons from low-pressure reservoir formations. Their design is dependent on predictive models used to optimize the system before implementation in the field. The greater the accuracy of these models, the better the performance of the pumping system in the field. The scope of this paper is to present an improved plunger slippage model, developed in connection to the pump test facility (PTF) and validated by field data.\u0000 This paper provides an analysis of plunger slippage. Existing plunger-slippage models are compared with field data. Based on the result of this comparison, an improved plunger-slippage model is derived based on the Navier-Stokes equation and dimensional analysis. Adjustments are applied to increase the model's validity. The mathematical and laboratory work have shown that a proper fit to reality requires four coefficients that make the equation an empirical one. An extensive laboratory test campaign, using real field equipment, was performed at the PTF at Montanuniversitaet Leoben (MUL). Numerous influencing parameters, such as plunger velocity, clearance magnitude, and fluid viscosity, were studied.\u0000 Historical plunger-slippage models overestimate the slippage rate, whereas field data showed that newer models underestimate the slippage rate. In general, dynamic models are more accurate than static slippage models. The fit of the four model coefficients, based on laboratory tests, indicate that the chosen strategy of using laboratory tests and allocating the results to field conditions has worked out. The comparison of the results obtained by the presented improved slippage model and the field tests indicate a good match.\u0000 The presented slippage model predicts the plunger slippage rate precisely and results in greater accuracy. The plunger wear rate approach is presented, which can be used to plan well interventions, decrease intervention costs, and increase the mean time between failures.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2020-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/202474-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42824960","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Hongli Chang, Yin Zhang, A. Dandekar, S. Ning, J. Barns, R. Edwards, W. Schulpen, D. Cercone, J. Ciferno
The first-ever field pilot on Alaska North Slope (ANS) to validate using polymer floods for heavy-oil enhanced oil recovery is currently ongoing. One of the major concerns of the operator is the effect of polymer on oil/water-separation efficiency after polymer breakthrough. This work investigates the influence of polymer on the separation behavior of heavy-oil emulsions and evaluates the performance of emulsion breakers (EBs). In this study, two types of heavy-oil emulsions were prepared and tested at 20 and 50% water cut (WC), respectively. The bottle test method was used in the experiments, in which the separated water volume with time, the separated water quality, and the volume fraction of phases were recorded. Results showed that polymer accelerated the oil/water separation acting as an emulsion inhibitor at 20% WC but tended to impede the water separation at 50% WC. Regardless of WC, polymer resulted in poor water quality and the formation of a stable intermediate oil in water (o/w) emulsion, because of the increased viscosity of the water phase. The performance of EBs showed a complex dependency on the WC, the type of demulsifier and dosage, and the polymer concentration. Despite the varied conditions encountered in the heavy-oil/water/polymer/demulsifier system, a compound EB achieved satisfactory demulsification performance, showing the highest potential for deployment in the current ANS polymer flooding pilot. In this paper, we systematically studied the potential influence of polymer breakthrough on the separation behavior of heavy-oil emulsion on ANS for the first time. The findings of this study will provide practical guidance in advance for produced fluid treatment of the ongoing first-ever polymer flooding pilot on ANS.
{"title":"Experimental Investigation on Separation Behavior of Heavy-Oil Emulsion for Polymer Flooding on Alaska North Slope","authors":"Hongli Chang, Yin Zhang, A. Dandekar, S. Ning, J. Barns, R. Edwards, W. Schulpen, D. Cercone, J. Ciferno","doi":"10.2118/200369-pa","DOIUrl":"https://doi.org/10.2118/200369-pa","url":null,"abstract":"\u0000 The first-ever field pilot on Alaska North Slope (ANS) to validate using polymer floods for heavy-oil enhanced oil recovery is currently ongoing. One of the major concerns of the operator is the effect of polymer on oil/water-separation efficiency after polymer breakthrough. This work investigates the influence of polymer on the separation behavior of heavy-oil emulsions and evaluates the performance of emulsion breakers (EBs). In this study, two types of heavy-oil emulsions were prepared and tested at 20 and 50% water cut (WC), respectively. The bottle test method was used in the experiments, in which the separated water volume with time, the separated water quality, and the volume fraction of phases were recorded. Results showed that polymer accelerated the oil/water separation acting as an emulsion inhibitor at 20% WC but tended to impede the water separation at 50% WC. Regardless of WC, polymer resulted in poor water quality and the formation of a stable intermediate oil in water (o/w) emulsion, because of the increased viscosity of the water phase. The performance of EBs showed a complex dependency on the WC, the type of demulsifier and dosage, and the polymer concentration. Despite the varied conditions encountered in the heavy-oil/water/polymer/demulsifier system, a compound EB achieved satisfactory demulsification performance, showing the highest potential for deployment in the current ANS polymer flooding pilot. In this paper, we systematically studied the potential influence of polymer breakthrough on the separation behavior of heavy-oil emulsion on ANS for the first time. The findings of this study will provide practical guidance in advance for produced fluid treatment of the ongoing first-ever polymer flooding pilot on ANS.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2020-06-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/200369-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42482052","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Sadegh Najafi, E. Hajidavalloo, A. Ghanbarzadeh, Hamed Gerami, S. M. Alavi
Growing demand for a subsurface pump application to perform artificial lift in low-pressure wells increases the necessity of a high-efficiency downhole separator to prevent gas entrance in the pump. The purpose of this study is to empirically investigate the efficiency of a helical downhole separator and provide suggestions for improving its performance. To make the results more practical, dimensionless numbers governing the problem were specified using dimensional analysis and the Buckingham theorem, and a laboratory-scale separator was built. Oil and air were selected as the working fluids for this experiment. The results of the experiments showed that the separator performance was divided into three regions: inefficiency region, rapid-growth region, and nongrowth region. To increase the separator efficiency, the separator was modified by blocking the initial holes of the inner tube to provide a region for developing the prerotational effect. The modified separator showed an increase in efficiency as much as 7%. In the third step, the number of holes that were blocked at the entrance region in the first modification were distributed in the rest of the inner tube so that the total hole area remains constant. The separator efficiency, in this case, was significantly increased compared with the previous two cases by as much as twofold. It was found that the inlet design of the separator significantly affects its performance.
{"title":"Performance Improvement of Helical Downhole Gas-Oil Separator Using Experimental Approach","authors":"Sadegh Najafi, E. Hajidavalloo, A. Ghanbarzadeh, Hamed Gerami, S. M. Alavi","doi":"10.2118/201227-pa","DOIUrl":"https://doi.org/10.2118/201227-pa","url":null,"abstract":"\u0000 Growing demand for a subsurface pump application to perform artificial lift in low-pressure wells increases the necessity of a high-efficiency downhole separator to prevent gas entrance in the pump. The purpose of this study is to empirically investigate the efficiency of a helical downhole separator and provide suggestions for improving its performance. To make the results more practical, dimensionless numbers governing the problem were specified using dimensional analysis and the Buckingham theorem, and a laboratory-scale separator was built. Oil and air were selected as the working fluids for this experiment. The results of the experiments showed that the separator performance was divided into three regions: inefficiency region, rapid-growth region, and nongrowth region. To increase the separator efficiency, the separator was modified by blocking the initial holes of the inner tube to provide a region for developing the prerotational effect. The modified separator showed an increase in efficiency as much as 7%. In the third step, the number of holes that were blocked at the entrance region in the first modification were distributed in the rest of the inner tube so that the total hole area remains constant. The separator efficiency, in this case, was significantly increased compared with the previous two cases by as much as twofold. It was found that the inlet design of the separator significantly affects its performance.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2020-06-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/201227-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44778646","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Avery, R. Large, H. Azhar, Kai San Wong, Mohd Faizal Yusoff
A successful rigless subsea stimulation was executed during 2018, with the intervention performed on three target wells offshore of Sabah Malaysia, at a water depth of approximately 1400 m (4,593 ft). Significant changes in reservoir performance prompted an acid-stimulation and scale-squeeze treatment, designed to remedy fines migration and scaling issues within the well and production system. Treatment fluids were delivered subsea by an open-water hydraulic access system, using a hybrid coiled tubing downline (HCTD). Access to the subsea trees was enabled by a novel choke-access technology, allowing for a flexible, cost-efficient, and low-risk intervention. The intervention system was installed on a multiservice vessel, with the downline deployed via the vessel moonpool. A second support vessel was used as required to provide additional fluid capacity without disturbing primary intervention operations. This enhanced the flexibility of the operation, accommodating potential changes in the treatment plan without impact to critical path-stimulation activities. The full intervention was delivered as an integrated service, with all elements supplied by a single provider, via one contract. An established network of in-house equipment, expertise, test laboratories, and operational bases supported the planning and execution of the project. This was complemented by select external providers for vessels, remotely operated vehicle services, and other specialist contractors. The challenges faced during execution included completion of a comprehensive treatment fluid test program, importation and logistics of equipment from around the globe, and managing operational risks, all within a condensed timeline to satisfy a brief intervention window. A collaborative solution was developed that combined the resources of the service provider, inclusion of performance-based elements within the contract, and delivery of an efficient and flexible well-access technology that supported rapid mobilization and alleviated operational risk. Post-stimulation well testing confirmed an average increase in oil productivity of 86%, with a corresponding productivity-index factor gain of 3.4. These results confirm the appropriateness of open-water hydraulic access using coiled tubing (CT) for performing cost-effective stimulations on complex subsea wells.
{"title":"Successful Rigless Subsea Stimulation in Asia Using Novel Well-Access Technology and a Fully Integrated Service Model","authors":"M. Avery, R. Large, H. Azhar, Kai San Wong, Mohd Faizal Yusoff","doi":"10.2118/197073-pa","DOIUrl":"https://doi.org/10.2118/197073-pa","url":null,"abstract":"\u0000 A successful rigless subsea stimulation was executed during 2018, with the intervention performed on three target wells offshore of Sabah Malaysia, at a water depth of approximately 1400 m (4,593 ft). Significant changes in reservoir performance prompted an acid-stimulation and scale-squeeze treatment, designed to remedy fines migration and scaling issues within the well and production system. Treatment fluids were delivered subsea by an open-water hydraulic access system, using a hybrid coiled tubing downline (HCTD). Access to the subsea trees was enabled by a novel choke-access technology, allowing for a flexible, cost-efficient, and low-risk intervention. The intervention system was installed on a multiservice vessel, with the downline deployed via the vessel moonpool. A second support vessel was used as required to provide additional fluid capacity without disturbing primary intervention operations. This enhanced the flexibility of the operation, accommodating potential changes in the treatment plan without impact to critical path-stimulation activities.\u0000 The full intervention was delivered as an integrated service, with all elements supplied by a single provider, via one contract. An established network of in-house equipment, expertise, test laboratories, and operational bases supported the planning and execution of the project. This was complemented by select external providers for vessels, remotely operated vehicle services, and other specialist contractors.\u0000 The challenges faced during execution included completion of a comprehensive treatment fluid test program, importation and logistics of equipment from around the globe, and managing operational risks, all within a condensed timeline to satisfy a brief intervention window. A collaborative solution was developed that combined the resources of the service provider, inclusion of performance-based elements within the contract, and delivery of an efficient and flexible well-access technology that supported rapid mobilization and alleviated operational risk.\u0000 Post-stimulation well testing confirmed an average increase in oil productivity of 86%, with a corresponding productivity-index factor gain of 3.4. These results confirm the appropriateness of open-water hydraulic access using coiled tubing (CT) for performing cost-effective stimulations on complex subsea wells.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2020-06-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/197073-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43847271","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Sand production has been a very serious concern for the high-pressure, high-temperature (HPHT) gas wells in the Tarim Basin. However, the possible reasons and mechanisms remain unclear because there is no sufficient model to predict both onset of sanding and sand-production rate. The objective of this study is to develop a three-dimensional (3D) numerical sand production-prediction model and apply it to these HPHT gas wells to determine the main mechanisms for sand production and to propose completion designs to minimize sand production. This paper presents the development of a fully coupled 3D, poro-elasto-plastic sand-production model and the simulation results for two key wells that are prone to sanding. The sand-production model was used to model the different completion designs and flowback strategies that were used in the field. The model couples multiphase fluid flow and elasto-plasticity to simulate pressure transient behavior and rock deformation during production. The sanding criterion is a combination of both mechanical failure (shear/tensile/compressive failure) and fluid erosion. A novel cell-removal algorithm has been implemented to predict the dynamic (time dependent) sand-production process. In addition, the complex geometry of the wells and perforations are explicitly modeled to show cavity propagation around hole/perforations during sand production. For this case study, triaxial tests on core samples were conducted, and the stress-strain curves under different confining stresses are analyzed to obtain rock properties for both the preyield and post-yield period. The wells were categorized into ones that had massive sand production and ones that showed much less sand production. Operational and mechanical factors that were empirically found to result in sand production were identified. The sand-production model was run to verify the role played by different factors. It is shown that completion design, rock strength, and post-failure behavior of the rock are key factors responsible for the observed sanding in these wells. In addition, the drawdown strategy and the associated bottomhole pressure (BHP) change and the extent of depletion play an important role in the sanding rate. Several strategies for minimizing sand production are suggested for these wells. These include drawdown management, completion, and perforation design. In this study, we show for the first time that data from HPHT gas wells that have severe sand-production problems can be analyzed quantitatively with the developed model to determine the mechanisms of sand production. This allows us to make operational recommendations to minimize sanding risk in these wells.
{"title":"Predicting Sand Production Rate in High-Pressure, High-Temperature Wells in the Tarim Basin","authors":"Hongtao Liu, Haotian Wang, Wei Zhang, Junyan Liu, Yutao Zhang, M. Sharma","doi":"10.2118/191406-pa","DOIUrl":"https://doi.org/10.2118/191406-pa","url":null,"abstract":"\u0000 Sand production has been a very serious concern for the high-pressure, high-temperature (HPHT) gas wells in the Tarim Basin. However, the possible reasons and mechanisms remain unclear because there is no sufficient model to predict both onset of sanding and sand-production rate. The objective of this study is to develop a three-dimensional (3D) numerical sand production-prediction model and apply it to these HPHT gas wells to determine the main mechanisms for sand production and to propose completion designs to minimize sand production. This paper presents the development of a fully coupled 3D, poro-elasto-plastic sand-production model and the simulation results for two key wells that are prone to sanding.\u0000 The sand-production model was used to model the different completion designs and flowback strategies that were used in the field. The model couples multiphase fluid flow and elasto-plasticity to simulate pressure transient behavior and rock deformation during production. The sanding criterion is a combination of both mechanical failure (shear/tensile/compressive failure) and fluid erosion. A novel cell-removal algorithm has been implemented to predict the dynamic (time dependent) sand-production process. In addition, the complex geometry of the wells and perforations are explicitly modeled to show cavity propagation around hole/perforations during sand production.\u0000 For this case study, triaxial tests on core samples were conducted, and the stress-strain curves under different confining stresses are analyzed to obtain rock properties for both the preyield and post-yield period. The wells were categorized into ones that had massive sand production and ones that showed much less sand production. Operational and mechanical factors that were empirically found to result in sand production were identified. The sand-production model was run to verify the role played by different factors. It is shown that completion design, rock strength, and post-failure behavior of the rock are key factors responsible for the observed sanding in these wells. In addition, the drawdown strategy and the associated bottomhole pressure (BHP) change and the extent of depletion play an important role in the sanding rate. Several strategies for minimizing sand production are suggested for these wells. These include drawdown management, completion, and perforation design. In this study, we show for the first time that data from HPHT gas wells that have severe sand-production problems can be analyzed quantitatively with the developed model to determine the mechanisms of sand production. This allows us to make operational recommendations to minimize sanding risk in these wells.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2020-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/191406-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49310924","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In this paper we examine the changes in the injectivity of wells reinjecting produced water in two fields from Block 17, offshore Angola. This analysis suggests that the water quality has a direct impact on well injectivity during matrix injection. Well impairment caused by desulfated seawater treated with membrane technology appears immaterial in comparison with the injectivity declines observed during produced-water reinjection (PWRI). The decline rate is much quicker for the field with the worst quality of treated produced water. Injectivity enhancements observed during seawater-injection tests demonstrate that the matrix decline is partially reversible. However, permanent damage also develops with time; it is not possible to recover the initial injectivity after a long period of injection with produced water. The analysis also shows that fracture injection can effectively mitigate the strong injectivity declines experienced in the field with the worst quality of treated produced water. Fracture injection comes with higher injection pressures, even when operating the wells at low flow rates. As a result, the injectivity index (II), as conventionally defined, displays a strong flow-rate dependency, making it inappropriate for measuring the well performance in fracture condition. Besides the limitations of the high injection pressures, fracture injection was found detrimental to injection conformance in wells with commingled water injection in several reservoir layers. In this situation, most of the injection is thought to take place in the shallowest layer where the fracture is likely to grow, leaving little injection for deeper reservoir layers.
{"title":"Produced-Water Reinjection in Deep Offshore Miocene Reservoirs, Block 17, Angola","authors":"M. Mainguy, S. Perrier, E. Buré","doi":"10.2118/197061-pa","DOIUrl":"https://doi.org/10.2118/197061-pa","url":null,"abstract":"\u0000 In this paper we examine the changes in the injectivity of wells reinjecting produced water in two fields from Block 17, offshore Angola. This analysis suggests that the water quality has a direct impact on well injectivity during matrix injection. Well impairment caused by desulfated seawater treated with membrane technology appears immaterial in comparison with the injectivity declines observed during produced-water reinjection (PWRI). The decline rate is much quicker for the field with the worst quality of treated produced water. Injectivity enhancements observed during seawater-injection tests demonstrate that the matrix decline is partially reversible. However, permanent damage also develops with time; it is not possible to recover the initial injectivity after a long period of injection with produced water.\u0000 The analysis also shows that fracture injection can effectively mitigate the strong injectivity declines experienced in the field with the worst quality of treated produced water. Fracture injection comes with higher injection pressures, even when operating the wells at low flow rates. As a result, the injectivity index (II), as conventionally defined, displays a strong flow-rate dependency, making it inappropriate for measuring the well performance in fracture condition. Besides the limitations of the high injection pressures, fracture injection was found detrimental to injection conformance in wells with commingled water injection in several reservoir layers. In this situation, most of the injection is thought to take place in the shallowest layer where the fracture is likely to grow, leaving little injection for deeper reservoir layers.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2020-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/197061-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48742146","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Crosslinked polymers extrude through fractures during placement of many conformance-improvement treatments, as well as during hydraulic fracturing. Dehydration of polymer gel during extrusion through fractures has often been observed and was extensively investigated during recent decades. Injection of highly viscous gel increases the pressure in a fracture, which promotes gel dehydration by fluid leakoff into the adjacent matrix. The present comprehension of gel behavior dictates that the rate of fluid leakoff will be controlled by the gel and fracture properties and, to a lesser extent, be affected by the properties of an adjacent porous medium. However, several experimental results, presented in this work, indicate that fluid leakoff deviates from expected behavior when oil is present in the fracture-adjacent matrix. We investigated fluid leakoff from chromium (Cr)(III)-acetate hydrolyzed polyacrylamide (HPAM) gels during extrusion through oil-saturated, fractured core plugs. The matrix properties were varied to evaluate the effect of pore size, permeability, and heterogeneity on gel dehydration and leakoff rate. A deviating leakoff behavior during gel propagation through fractured, oil-saturated core plugs was observed, associated with the formation of a capillary driven displacement front in the matrix. Magnetic resonance imaging (MRI) was used to monitor water leakoff in a fractured, oil-saturated, carbonate core plug and verified the position and existence of a stable displacement front. The use of MRI also identified the presence of wormholes in the gel, during and after gel placement, which supports gel behavior similar to the previously proposed Seright filter-cake model. An explanation is offered for when the matrix affects gel dehydration and is supported by imaging. Our results show that the properties of a reservoir rock might affect gel dehydration, which, in turn, strongly affects the depth of gel penetration into a fracture network and the gel strength during chase floods.
{"title":"Water Leakoff During Gel Placement in Fractures: Extension to Oil-Saturated Porous Media","authors":"B. Brattekås, R. Seright, G. Ersland","doi":"10.2118/190256-PA","DOIUrl":"https://doi.org/10.2118/190256-PA","url":null,"abstract":"\u0000 Crosslinked polymers extrude through fractures during placement of many conformance-improvement treatments, as well as during hydraulic fracturing. Dehydration of polymer gel during extrusion through fractures has often been observed and was extensively investigated during recent decades. Injection of highly viscous gel increases the pressure in a fracture, which promotes gel dehydration by fluid leakoff into the adjacent matrix. The present comprehension of gel behavior dictates that the rate of fluid leakoff will be controlled by the gel and fracture properties and, to a lesser extent, be affected by the properties of an adjacent porous medium. However, several experimental results, presented in this work, indicate that fluid leakoff deviates from expected behavior when oil is present in the fracture-adjacent matrix. We investigated fluid leakoff from chromium (Cr)(III)-acetate hydrolyzed polyacrylamide (HPAM) gels during extrusion through oil-saturated, fractured core plugs. The matrix properties were varied to evaluate the effect of pore size, permeability, and heterogeneity on gel dehydration and leakoff rate. A deviating leakoff behavior during gel propagation through fractured, oil-saturated core plugs was observed, associated with the formation of a capillary driven displacement front in the matrix. Magnetic resonance imaging (MRI) was used to monitor water leakoff in a fractured, oil-saturated, carbonate core plug and verified the position and existence of a stable displacement front. The use of MRI also identified the presence of wormholes in the gel, during and after gel placement, which supports gel behavior similar to the previously proposed Seright filter-cake model. An explanation is offered for when the matrix affects gel dehydration and is supported by imaging. Our results show that the properties of a reservoir rock might affect gel dehydration, which, in turn, strongly affects the depth of gel penetration into a fracture network and the gel strength during chase floods.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2020-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/190256-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46692221","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The artificial lift (AL) system is the most efficient production technique in optimizing production from the unconventional horizontal oil and gas wells. Nonetheless, due to declining reservoir pressure during the production life of a well, artificial lifting of oil and gas remains a critical issue. Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of AL in tight formations, there remains differing assessments of the best approach, AL type, optimum time, and conditions to install AL during the life of a well. This report presents a comprehensive review of AL system application with specific focus on tight oil and gas formations across the world. The review focuses on over 35 successful and unsuccessful field tests in the unconventional horizontal wells over the past few decades. The purpose is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed.
{"title":"Artificial Lift System Applications in Tight Formations: The State of Knowledge","authors":"O. Kolawole, T. Gamadi, Denny B. Bullard","doi":"10.2118/196592-pa","DOIUrl":"https://doi.org/10.2118/196592-pa","url":null,"abstract":"\u0000 The artificial lift (AL) system is the most efficient production technique in optimizing production from the unconventional horizontal oil and gas wells. Nonetheless, due to declining reservoir pressure during the production life of a well, artificial lifting of oil and gas remains a critical issue. Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of AL in tight formations, there remains differing assessments of the best approach, AL type, optimum time, and conditions to install AL during the life of a well. This report presents a comprehensive review of AL system application with specific focus on tight oil and gas formations across the world. The review focuses on over 35 successful and unsuccessful field tests in the unconventional horizontal wells over the past few decades. The purpose is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"35 1","pages":"422-434"},"PeriodicalIF":1.2,"publicationDate":"2020-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/196592-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46136735","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Ricardo S. Fraga, Octavio G. S. Castellões, B. W. Assmann, V. Estevam, Greco Tusset de Moura, I. N. Schröer, Luiz G. do Amaral
This paper reports the first experience on applying progressive vortex pumping (PVP) as an artificial lift solution in the oil industry. From a conceptual point of view, progressive vortex pumps are rotodynamic devices that elevate fluid mixtures by converting kinetic energy to potential energy, which is a result of an inducing vortex within each pumping stage. The solution proposed in this paper was inspired by pumps used in the automotive industry (Lochman and Bryce 1980; Yu 1995) and adapted for pumping multiphase mixtures from oil-producing reservoirs. The pilot installation of this technology occurred in an onshore field, located northeast of Brazil. There is a brief description about some specificities of the progressive vortex pump (including features of the production scenario, surface and subsurface installations, and the results observed during the first 4 months of operation), which was installed in an unprecedented way in an oil production well. This paper also addresses some relative advantages of PVP over other artificial lift pumping methods, such as electric submersible pumping (ESP). However, overall efficiency needs to be improved when compared to competing methods such as ESP.
{"title":"Progressive Vortex Pump: A New Artificial Lift Pumped Method","authors":"Ricardo S. Fraga, Octavio G. S. Castellões, B. W. Assmann, V. Estevam, Greco Tusset de Moura, I. N. Schröer, Luiz G. do Amaral","doi":"10.2118/200497-pa","DOIUrl":"https://doi.org/10.2118/200497-pa","url":null,"abstract":"\u0000 This paper reports the first experience on applying progressive vortex pumping (PVP) as an artificial lift solution in the oil industry. From a conceptual point of view, progressive vortex pumps are rotodynamic devices that elevate fluid mixtures by converting kinetic energy to potential energy, which is a result of an inducing vortex within each pumping stage. The solution proposed in this paper was inspired by pumps used in the automotive industry (Lochman and Bryce 1980; Yu 1995) and adapted for pumping multiphase mixtures from oil-producing reservoirs. The pilot installation of this technology occurred in an onshore field, located northeast of Brazil. There is a brief description about some specificities of the progressive vortex pump (including features of the production scenario, surface and subsurface installations, and the results observed during the first 4 months of operation), which was installed in an unprecedented way in an oil production well. This paper also addresses some relative advantages of PVP over other artificial lift pumping methods, such as electric submersible pumping (ESP). However, overall efficiency needs to be improved when compared to competing methods such as ESP.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"35 1","pages":"454-463"},"PeriodicalIF":1.2,"publicationDate":"2020-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/200497-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42272930","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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