Nader Y. BuKhamseen, M. Maučec, Anwar R. Awan, A. Saffar, Jorge E. Nieto
Presence of paleo zone, which frequently exists below Free-Water-Level surface, can impact dynamic reconciliation of reservoir simulation models. The process is even more challenging with embedded complex representations of reservoir connectivity (conductive fractures) and inherent uncertainty associated with geological and flow modeling. We present a rigorous approach that integrates characterization of paleo zone, parameterization of paleo zone conductivity and application of flow profiles as a guide in accelerated history matching study of large-scale Dual Porosity-Dual Permeability model. The presence of immobile oil within paleo zone can cause permeability reduction and inherently limit aquifer support to oil zone. Accordingly, such occurrence can be represented as a low permeability streak or region in the simulation model and leveraged for more accurate calibration of model injection wells located inside the paleo zone. We performed probabilistic sensitivity analysis and parameterization of paleo zone conductivity using Design of Experiments on a synthetic simulation model with optimized aquifer size and strength as the basecase. The outcome of the synthetic sensitivity scenarios using dynamic model strongly indicates that paleo zone is partially sealing. Multiple scoping runs were performed to identify appropriate permeability values required to calibrate the model. The use of multipliers in porositypermeability transform reproduces blocking or baffling effect of the paleo zone, considering this fluid will behave as part of the rock framework. Porosity and permeability were recomputed inside the paleo zone based on Bulk Volume of Water (BVW) data assessment. The higher the BVW the higher the chance to have effective communication between the oil leg and aquifer. These multipliers represent the probability of the sealing character of the paleo zone and reflect on the non-uniform distribution of accumulated hydrocarbons. Above methodology was used to define the initial set of paleo zone petrophysical property modifiers, rendering multiple model realizations within optimistic-pessimistic range. Flow profiles can be used to guide segmentation of paleo zone with preferential well injectivity to further improve the efficiency of history matching process. Our paper demonstrates a successful application of multi-variate characterization and modeling of paleo zone geometry and properties for a history match of a conceptual, complex reservoir simulation model under reservoir uncertainty. An innovative approach to probabilistic parameterization of paleo zone conductivity has contributed to a model with exceptionally high quality and rendered a reservoir simulation model with reliable predictive capability in accelerated time.
自由水位面下频繁存在的古带，会影响储层模拟模型的动态调和。由于储层连通性(导电裂缝)的复杂表征以及地质和流动建模的固有不确定性，这一过程更具挑战性。提出了一种集古带表征、古带电导率参数化和流动剖面应用于一体的严格方法，以指导大规模双孔双渗模型的加速历史拟合研究。古带内不动油的存在会导致渗透率降低，固有地限制了含水层对油层的支撑。因此，这种产状可以在模拟模型中表示为低渗透条纹或区域，并用于更准确地校准位于古带内的模型注水井。在以优化含水层尺寸和强度为基础的综合模拟模型上，采用实验设计方法对古带电导率进行了概率敏感性分析和参数化。动态模型综合敏感性情景的结果强烈表明古带是部分封闭的。为了确定校准模型所需的适当渗透率值，进行了多次范围测量。考虑到这些流体将作为岩石框架的一部分，在孔隙度-渗透率变换中使用乘数可以再现古带的阻塞或阻塞效应。根据水体积(Bulk Volume of Water, BVW)数据评估，重新计算了古带内孔隙度和渗透率。BVW越高，油腿与含水层之间有效连通的机会就越大。这些乘数反映了古带封闭性的概率，反映了油气聚集分布的不均匀性。利用上述方法定义了古带岩石物性修正因子的初始集，在乐观-悲观范围内实现了多个模型。利用流动剖面可以指导具有优先注水井的古带分段，进一步提高历史匹配过程的效率。本文展示了在储层不确定性下，将古带几何和性质的多变量表征和建模成功应用于概念性复杂储层模拟模型的历史匹配。一种创新的古带电导率概率参数化方法有助于建立高质量的模型，并使储层模拟模型在加速时间内具有可靠的预测能力。
{"title":"Rigorous Multi-Variate Characterization and Modeling of Paleo Zone for Simulation Model History Matching under Reservoir Uncertainty","authors":"Nader Y. BuKhamseen, M. Maučec, Anwar R. Awan, A. Saffar, Jorge E. Nieto","doi":"10.2523/iptc-22034-ms","DOIUrl":"https://doi.org/10.2523/iptc-22034-ms","url":null,"abstract":"\u0000 Presence of paleo zone, which frequently exists below Free-Water-Level surface, can impact dynamic reconciliation of reservoir simulation models. The process is even more challenging with embedded complex representations of reservoir connectivity (conductive fractures) and inherent uncertainty associated with geological and flow modeling. We present a rigorous approach that integrates characterization of paleo zone, parameterization of paleo zone conductivity and application of flow profiles as a guide in accelerated history matching study of large-scale Dual Porosity-Dual Permeability model. The presence of immobile oil within paleo zone can cause permeability reduction and inherently limit aquifer support to oil zone. Accordingly, such occurrence can be represented as a low permeability streak or region in the simulation model and leveraged for more accurate calibration of model injection wells located inside the paleo zone. We performed probabilistic sensitivity analysis and parameterization of paleo zone conductivity using Design of Experiments on a synthetic simulation model with optimized aquifer size and strength as the basecase. The outcome of the synthetic sensitivity scenarios using dynamic model strongly indicates that paleo zone is partially sealing. Multiple scoping runs were performed to identify appropriate permeability values required to calibrate the model. The use of multipliers in porositypermeability transform reproduces blocking or baffling effect of the paleo zone, considering this fluid will behave as part of the rock framework. Porosity and permeability were recomputed inside the paleo zone based on Bulk Volume of Water (BVW) data assessment. The higher the BVW the higher the chance to have effective communication between the oil leg and aquifer. These multipliers represent the probability of the sealing character of the paleo zone and reflect on the non-uniform distribution of accumulated hydrocarbons. Above methodology was used to define the initial set of paleo zone petrophysical property modifiers, rendering multiple model realizations within optimistic-pessimistic range. Flow profiles can be used to guide segmentation of paleo zone with preferential well injectivity to further improve the efficiency of history matching process. Our paper demonstrates a successful application of multi-variate characterization and modeling of paleo zone geometry and properties for a history match of a conceptual, complex reservoir simulation model under reservoir uncertainty. An innovative approach to probabilistic parameterization of paleo zone conductivity has contributed to a model with exceptionally high quality and rendered a reservoir simulation model with reliable predictive capability in accelerated time.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"116 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86214893","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}
V. Huerta, Christopher Villafuerte, Daniel Alarcon
This study shows the technical principles and methodology to design, execute, as well as do a reasonable analysis and interpretation of well tests in siliciclastic tight sands; Instead, Mini-fall-off pressure tests are the best alternative to assess earth-mechanical properties, to identify flow regimes (linear from radial), estimate reservoir pressure and effective permeability, and eventually, to calculate post-frac system permeability. In addition, rate transient analysis (RTA) incorporates dynamic surveillance data (pressure and production) to build a model allowing identifying boundary effects and predicting production performance with few history data. "G" function and After Closure Analysis (ACA) are used to estimate effective permeability and reservoir pressure, using surface pressure data from Mini-fall off test converted to bottomhole conditions. Then, pressure dynamic analysis is followed by using production data and wellhead pressure monitoring, with a "good-match" VLP correlation; Fetkovich's, Agarwal's and Blasingame's plots are prepared for a sound diagnostic to identify early time features (presence of micro-fractures, unusual wellbore storage, variable skin effect, flow regimes of hydraulic fracturing), verify reservoir model, and distinguish boundary effects such as: non-flow limit, presence of faults, barriers and lateral changes in reservoir properties. Finally, a type curve is prepared to forecast oil rates based on a prediction of wellhead pressure performance during lifetime. In general terms, mini-fall off tests allowed estimating reservoir properties of tight sandstones of Mogollón and Pariñas formation. With a reasonable degree of accuracy. Originally or partially depleted pressure conditions were able to be measured, as well as effective permeability estimations below 1 mD. In addition, half-lengths in between 70' and 100' were detected in most of the hydraulic fracturing jobs. On the other hand, in some cases, a micro-natural fractured system was identified during an early-time regime by a computer-aided-RTA-model with a reasonable match of Fetkovich's and Blasingame's plots. This behavior explains the high productivity indexes and initial rates founded in some hydraulic fracturing jobs, such as the case of well 3 on Peña Negra field; The RTA model shows an accurate history match (95%) after a two-year production phase. This methodology proposes the integration of mini-fall off tests to test and account for reservoir properties and rate transient analysis, to identify reservoir boundaries while monitoring production performance. The methodology incorporates and adapt the following techniques to low permeability reservoirs: "G" function and After Closure Analysis (ACA) to estimate effective permeability and reservoir pressureFetkovich's and Blasingame's plots to identify early-time featuresBlasingame's plot to model hydraulic fracturing features (half-length and width, Fc) and figure out boundary effects (faults, no
{"title":"Well Testing Analysis and Interpretation in Low Permeability Reservoirs: Theory and Applications for Tight Oil Reservoirs in Peruvian Northwest Fields","authors":"V. Huerta, Christopher Villafuerte, Daniel Alarcon","doi":"10.2523/iptc-22481-ms","DOIUrl":"https://doi.org/10.2523/iptc-22481-ms","url":null,"abstract":"\u0000 This study shows the technical principles and methodology to design, execute, as well as do a reasonable analysis and interpretation of well tests in siliciclastic tight sands; Instead, Mini-fall-off pressure tests are the best alternative to assess earth-mechanical properties, to identify flow regimes (linear from radial), estimate reservoir pressure and effective permeability, and eventually, to calculate post-frac system permeability. In addition, rate transient analysis (RTA) incorporates dynamic surveillance data (pressure and production) to build a model allowing identifying boundary effects and predicting production performance with few history data.\u0000 \"G\" function and After Closure Analysis (ACA) are used to estimate effective permeability and reservoir pressure, using surface pressure data from Mini-fall off test converted to bottomhole conditions. Then, pressure dynamic analysis is followed by using production data and wellhead pressure monitoring, with a \"good-match\" VLP correlation; Fetkovich's, Agarwal's and Blasingame's plots are prepared for a sound diagnostic to identify early time features (presence of micro-fractures, unusual wellbore storage, variable skin effect, flow regimes of hydraulic fracturing), verify reservoir model, and distinguish boundary effects such as: non-flow limit, presence of faults, barriers and lateral changes in reservoir properties. Finally, a type curve is prepared to forecast oil rates based on a prediction of wellhead pressure performance during lifetime.\u0000 In general terms, mini-fall off tests allowed estimating reservoir properties of tight sandstones of Mogollón and Pariñas formation. With a reasonable degree of accuracy. Originally or partially depleted pressure conditions were able to be measured, as well as effective permeability estimations below 1 mD. In addition, half-lengths in between 70' and 100' were detected in most of the hydraulic fracturing jobs. On the other hand, in some cases, a micro-natural fractured system was identified during an early-time regime by a computer-aided-RTA-model with a reasonable match of Fetkovich's and Blasingame's plots. This behavior explains the high productivity indexes and initial rates founded in some hydraulic fracturing jobs, such as the case of well 3 on Peña Negra field; The RTA model shows an accurate history match (95%) after a two-year production phase.\u0000 This methodology proposes the integration of mini-fall off tests to test and account for reservoir properties and rate transient analysis, to identify reservoir boundaries while monitoring production performance. The methodology incorporates and adapt the following techniques to low permeability reservoirs: \"G\" function and After Closure Analysis (ACA) to estimate effective permeability and reservoir pressureFetkovich's and Blasingame's plots to identify early-time featuresBlasingame's plot to model hydraulic fracturing features (half-length and width, Fc) and figure out boundary effects (faults, no","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86736584","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}
The artificial well-testing interpretation is a good tool for parameter evaluations, performance predictions, and strategy designs. However, non-unique solutions and computational inefficiencies are obstacles to practical interpretation, especially when artificial fractures are considered. Under this situation, a new deep reinforcement learning (DRL) based approach is proposed for automatic curve matching on vertically fractured well-testing interpretation. Based on deep deterministic policy gradient (DDPG) algorithm, the proposed DRL approach is successfully applied to automatic matching of well test curves. In addition, to improve the training efficiency, a surrogate model of the vertically fractured well test model based on LSTM neural network was established. Through episodic training, the agent finally converged to an optimal curve matching policy on vertically fractured well-testing model through interaction with the surrogate model. The results show that the average relative error of the curve parameter interpretation is less than 6%. Additionally, the results from the case studies show that the proposed DRL approach has a high calculation speed, and the average computing time was 0.44 seconds. The proposed DRL approach also has high accuracy in field cases, and the average relative error was 7.15%, which show the reliability of the proposed DRL method.
{"title":"An Efficient Approach for Automatic Well-Testing Interpretation Based on Surrogate Model and Deep Reinforcement Learning","authors":"Peng Dong, X. Liao, Zhiming Chen, Hongyan Zhao","doi":"10.2523/iptc-22072-ms","DOIUrl":"https://doi.org/10.2523/iptc-22072-ms","url":null,"abstract":"\u0000 The artificial well-testing interpretation is a good tool for parameter evaluations, performance predictions, and strategy designs. However, non-unique solutions and computational inefficiencies are obstacles to practical interpretation, especially when artificial fractures are considered. Under this situation, a new deep reinforcement learning (DRL) based approach is proposed for automatic curve matching on vertically fractured well-testing interpretation.\u0000 Based on deep deterministic policy gradient (DDPG) algorithm, the proposed DRL approach is successfully applied to automatic matching of well test curves. In addition, to improve the training efficiency, a surrogate model of the vertically fractured well test model based on LSTM neural network was established. Through episodic training, the agent finally converged to an optimal curve matching policy on vertically fractured well-testing model through interaction with the surrogate model.\u0000 The results show that the average relative error of the curve parameter interpretation is less than 6%. Additionally, the results from the case studies show that the proposed DRL approach has a high calculation speed, and the average computing time was 0.44 seconds. The proposed DRL approach also has high accuracy in field cases, and the average relative error was 7.15%, which show the reliability of the proposed DRL method.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89041842","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}
O. Mullins, S. Pan, Kang Wang, S. Betancourt, Jesus A. Cañas, A. Kauerauf
Viscous oil and tar mats often occur at and near the oil-water contact (OWC) and can result from multiple charges of incompatible fluids with regard to asphaltene stability. The most easily measured oilfield case is gas charge into oil, where the increase of solution gas near the gas-oil contact (GOC) causes local instability of asphaltenes which can then lead to viscous oil and tar mats at the OWC. However, the detailed mechanisms that occur in geologic time to transport destabilized asphaltenes over large distances from the GOC to the OWC has yet to be fully resolved. Asphaltene destabilization towards the top of the reservoir, transport and accumulation at the base of the reservoir can be treated within a conceptual multistep process: instability driven by diffusion of light ends into the oil at the GOC, Stokes falling and diffusion of asphaltene nanocolloidal particles to the base of the interval, convective transport to the base of the reservoir, and finally, local asphaltene equilibration at the base of the reservoir. This conceptual model lays the foundation and provides the framework for forward modeling the formation of viscous oil and tar mats at the OWC. Here we introduce a simple, one-dimension composite model that accounts for all key physics and chemistry aspects of asphaltene instability, transport outcomes and bulk phase transition. This model can be used to predict different reservoir realizations given specific charge fluids, timing of charge, and reservoir attributes. This model employs the asphaltene thermodynamic equation, the Flory-Huggins-Zuo equation of state, and its reliance on the asphaltene nanostructures in the Yen-Mullins model and is shown to be applicable from nanoscale to macroscale. In a broader context, these reservoir processes fall within the new technical discipline ‘reservoir fluid geodynamics’. The target applications for this modeling include identification of possible key reservoir performance drivers through generation of different possible reservoir realizations and as a job planner for data acquisition and analysis to differentiate among reservoir realizations for optimization of field development planning. This approach is a template for forward modeling a broad array of fluid and rock complexities through a comprehensive deposition, trap filling and geodynamics perspective.
{"title":"Modeling Viscous Oil and Tar Mat Formation from Nanoscale to Macroscale","authors":"O. Mullins, S. Pan, Kang Wang, S. Betancourt, Jesus A. Cañas, A. Kauerauf","doi":"10.2523/iptc-22380-ms","DOIUrl":"https://doi.org/10.2523/iptc-22380-ms","url":null,"abstract":"\u0000 Viscous oil and tar mats often occur at and near the oil-water contact (OWC) and can result from multiple charges of incompatible fluids with regard to asphaltene stability. The most easily measured oilfield case is gas charge into oil, where the increase of solution gas near the gas-oil contact (GOC) causes local instability of asphaltenes which can then lead to viscous oil and tar mats at the OWC. However, the detailed mechanisms that occur in geologic time to transport destabilized asphaltenes over large distances from the GOC to the OWC has yet to be fully resolved. Asphaltene destabilization towards the top of the reservoir, transport and accumulation at the base of the reservoir can be treated within a conceptual multistep process: instability driven by diffusion of light ends into the oil at the GOC, Stokes falling and diffusion of asphaltene nanocolloidal particles to the base of the interval, convective transport to the base of the reservoir, and finally, local asphaltene equilibration at the base of the reservoir. This conceptual model lays the foundation and provides the framework for forward modeling the formation of viscous oil and tar mats at the OWC. Here we introduce a simple, one-dimension composite model that accounts for all key physics and chemistry aspects of asphaltene instability, transport outcomes and bulk phase transition. This model can be used to predict different reservoir realizations given specific charge fluids, timing of charge, and reservoir attributes. This model employs the asphaltene thermodynamic equation, the Flory-Huggins-Zuo equation of state, and its reliance on the asphaltene nanostructures in the Yen-Mullins model and is shown to be applicable from nanoscale to macroscale. In a broader context, these reservoir processes fall within the new technical discipline ‘reservoir fluid geodynamics’. The target applications for this modeling include identification of possible key reservoir performance drivers through generation of different possible reservoir realizations and as a job planner for data acquisition and analysis to differentiate among reservoir realizations for optimization of field development planning. This approach is a template for forward modeling a broad array of fluid and rock complexities through a comprehensive deposition, trap filling and geodynamics perspective.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90039432","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}
Well was drilled in Al Nouf field with the objective to support the pressure sustainability of multiple producer wells across Shuaiba-1 formation based on MRC / ERD approach. This paper presents the challenges faced in planning and drilling of subject well and successfully running of slim lower completion to total measured depth of 21,000ft (6.4 km) with having horizontal section of 10,450ft (3.18 km) with directional difficulty index (DDI) of 6.520 using slim casing design. Planning of this well commenced by meetings and collaboration with subsurface operation and reservoir team with the common objective of drilling a well of over 11,000ft horizontal extent and having a capability of running 4 ½" pre-perforated liner with multiple swell packers as lower completion to well TD of (21,000ft) across Shauiba - 1 reservoir. Purpose of lower completion are to properly control the well injectivity regime and support multiple producers across SH-1. All the associated risks were highlighted and mitigated by proper planning and engineering analysis such as trajectory, collision risks, BHA, hydraulics and casing design. This MRC injector well of 21,000ft MD / 8953 ft TVD (2.34 ERD H:V ratio) is the first well in the region to have 11,000ft of geo-steered 6" horizontal section with slim lower completion installed till TD of well. This paper will explain the innovative approach of mitigating the challenges faced while drilling a complex well of 3500ft departure and have a horizontal section of over 11,000ft with 6" drainage. A few challenges like collision risk at surface & horizontal section with total losses across aquifer were major disquiet but successfully catered. Second major challenge was to run 4 ½" pre-perforated liner of 11,000ft with multiple swell packers (each 1000ft) to TD of well were immaculately mitigated with advanced engineering analysis and innovative technologies like swivel master etc. Results from this well have proven that having lower completion in MRC / ERD wells have significantly improved the well accessibility and well performance and enhanced the reservoir management and significantly reduced the field development cost. This paper summarizes the practice and technology used to drill successfully the MRC / ERD well in artificial island and running of slim lower completion across horizontal section till TD of well. The challenges and its mitigation explained in this paper will support the idea of having lower completion in MRC/ERD wells which helps to stretch the reservoir boundaries and have more control on injectivity / productivity of reservoir because of proper isolation by swell packers and have maximum well accessibility across ERD horizontal section.
{"title":"Planning and Execution of MRC / ERD Well with Slim Lower Completion PPL in Al Nouf Field, Abu Dhabi, UAE","authors":"M. A. Hashmi","doi":"10.2523/iptc-21958-ms","DOIUrl":"https://doi.org/10.2523/iptc-21958-ms","url":null,"abstract":"\u0000 Well was drilled in Al Nouf field with the objective to support the pressure sustainability of multiple producer wells across Shuaiba-1 formation based on MRC / ERD approach. This paper presents the challenges faced in planning and drilling of subject well and successfully running of slim lower completion to total measured depth of 21,000ft (6.4 km) with having horizontal section of 10,450ft (3.18 km) with directional difficulty index (DDI) of 6.520 using slim casing design.\u0000 Planning of this well commenced by meetings and collaboration with subsurface operation and reservoir team with the common objective of drilling a well of over 11,000ft horizontal extent and having a capability of running 4 ½\" pre-perforated liner with multiple swell packers as lower completion to well TD of (21,000ft) across Shauiba - 1 reservoir. Purpose of lower completion are to properly control the well injectivity regime and support multiple producers across SH-1.\u0000 All the associated risks were highlighted and mitigated by proper planning and engineering analysis such as trajectory, collision risks, BHA, hydraulics and casing design.\u0000 This MRC injector well of 21,000ft MD / 8953 ft TVD (2.34 ERD H:V ratio) is the first well in the region to have 11,000ft of geo-steered 6\" horizontal section with slim lower completion installed till TD of well.\u0000 This paper will explain the innovative approach of mitigating the challenges faced while drilling a complex well of 3500ft departure and have a horizontal section of over 11,000ft with 6\" drainage. A few challenges like collision risk at surface & horizontal section with total losses across aquifer were major disquiet but successfully catered. Second major challenge was to run 4 ½\" pre-perforated liner of 11,000ft with multiple swell packers (each 1000ft) to TD of well were immaculately mitigated with advanced engineering analysis and innovative technologies like swivel master etc.\u0000 Results from this well have proven that having lower completion in MRC / ERD wells have significantly improved the well accessibility and well performance and enhanced the reservoir management and significantly reduced the field development cost.\u0000 This paper summarizes the practice and technology used to drill successfully the MRC / ERD well in artificial island and running of slim lower completion across horizontal section till TD of well.\u0000 The challenges and its mitigation explained in this paper will support the idea of having lower completion in MRC/ERD wells which helps to stretch the reservoir boundaries and have more control on injectivity / productivity of reservoir because of proper isolation by swell packers and have maximum well accessibility across ERD horizontal section.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79184968","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 study was conducted on Field M to assess CO2 storage potential and to evaluate the risks and uncertainties based on an integrated dynamic-geomechanics modeling approach. Field M is located at north of Central Luconia Province in Sarawak Basin, Malaysia. Most of the depleted carbonate formation in Sarawak Basin undergone pore collapse at various rates during its production life. In order to consider the impact of pore collapse towards reservoir properties, a seamless coupling simulation approach between dynamic model and geomechanics model is important to generate robust storage capacity and storage containment integrity assessment. The high abandonment pressure, uncertainties caused by reservoir compaction during the production life and subsequent injection period, and the risk of CO2 leakage from the reservoir due to fault re-activation and cap-rock integrity breach by the injection operations are also evaluated. The assessment was undertaken by building the compositional dynamic model that was then history matched in standalone mode to the historical production data with a reasonable quality index. The dynamic model grid was embedded with overburden, underburden and sideburden in the geomechanics model grid, and the reservoir properties and embedment grid properties were then populated in the geomechanics model. This process was followed by another history match in 2-way fully coupled dynamic-geomechanics modeling approach whereby the reservoir production and pressure depletion, and subsidence were matched. Injection simulations were subsequently conducted to assess the impact of reservoir compaction, trapping mechanisms, fault stability and cap-rock integrity towards achieving the maximum injectivity and storage capacity. It was observed that 4.41% of porosity and 12.11% of permeability reduction associated with reservoir compaction occurred during production whilst there was limited reversal in both parameters’ reduction during injection as the rock deformation was largely irreversible plastic deformation. The simulated subsidence was matched with the actual 20-year GPS subsidence measurement data collected at platform location. This history matched 2-way fully coupled model was subsequently used as the base case for simulating the CO2 injection options. The simulations showed that Field M has the potential to store up to 2.3 Tscf until the pressure reaches the cap-rock pressure limit. The simulations also showed that all the faults and cap-rock maintained their integrity and the seabed uplifted by 0.05 ft during the end of injection period. This paper provides a detailed description on CO2 storage site assessment using a 2-way fully coupled dynamic-geomechanics modeling approach in a highly porous carbonate reservoir which addresses trapping mechanisms, fault stability and cap-rock integrity, and their impact on injectivity and storage capacity. The information may be adopted for evaluation of other CO2 storage projects in b oth carbonat
{"title":"Integrated 2-Way Fully Coupled Reservoir Dynamic-Geomechanical Modelling Approach for CO2 Storage Risk Assessment in a Malaysian Carbonate Field","authors":"M. A. Mustafa, S. S. M Ali, M. H. Yakup, C. Tan","doi":"10.2523/iptc-22685-ms","DOIUrl":"https://doi.org/10.2523/iptc-22685-ms","url":null,"abstract":"\u0000 A study was conducted on Field M to assess CO2 storage potential and to evaluate the risks and uncertainties based on an integrated dynamic-geomechanics modeling approach. Field M is located at north of Central Luconia Province in Sarawak Basin, Malaysia. Most of the depleted carbonate formation in Sarawak Basin undergone pore collapse at various rates during its production life. In order to consider the impact of pore collapse towards reservoir properties, a seamless coupling simulation approach between dynamic model and geomechanics model is important to generate robust storage capacity and storage containment integrity assessment. The high abandonment pressure, uncertainties caused by reservoir compaction during the production life and subsequent injection period, and the risk of CO2 leakage from the reservoir due to fault re-activation and cap-rock integrity breach by the injection operations are also evaluated. The assessment was undertaken by building the compositional dynamic model that was then history matched in standalone mode to the historical production data with a reasonable quality index. The dynamic model grid was embedded with overburden, underburden and sideburden in the geomechanics model grid, and the reservoir properties and embedment grid properties were then populated in the geomechanics model. This process was followed by another history match in 2-way fully coupled dynamic-geomechanics modeling approach whereby the reservoir production and pressure depletion, and subsidence were matched. Injection simulations were subsequently conducted to assess the impact of reservoir compaction, trapping mechanisms, fault stability and cap-rock integrity towards achieving the maximum injectivity and storage capacity. It was observed that 4.41% of porosity and 12.11% of permeability reduction associated with reservoir compaction occurred during production whilst there was limited reversal in both parameters’ reduction during injection as the rock deformation was largely irreversible plastic deformation. The simulated subsidence was matched with the actual 20-year GPS subsidence measurement data collected at platform location. This history matched 2-way fully coupled model was subsequently used as the base case for simulating the CO2 injection options. The simulations showed that Field M has the potential to store up to 2.3 Tscf until the pressure reaches the cap-rock pressure limit. The simulations also showed that all the faults and cap-rock maintained their integrity and the seabed uplifted by 0.05 ft during the end of injection period. This paper provides a detailed description on CO2 storage site assessment using a 2-way fully coupled dynamic-geomechanics modeling approach in a highly porous carbonate reservoir which addresses trapping mechanisms, fault stability and cap-rock integrity, and their impact on injectivity and storage capacity. The information may be adopted for evaluation of other CO2 storage projects in b oth carbonat","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"75 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83378378","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}
Sergio Moncayo, Sandra Szlapa, Ahmed Aljanahi, Sayed Abdelrady
An innovative BHA was designed to fit slim extended reach wellbore profiles. Precise BHA design was essential to reach the bottom of the well with a scrapper and circulate to clean the hole efficiently for enabling fracking operations with Plug & Perf technology to be performed in extended reach horizontal wells in Bahrain. Plug & Perf operations for multistage fracking required to run plugs through a cased extended horizontal section with an internal diameter of 4" to isolate the different stages to be stimulated. The max OD of the plug was 3.625 in leaving a marginal clearance between the plug and the casing, making hole cleaning the primary risk to deal with. For hole cleaning it was important to design the slim BHA with a maximum OD of 3.125 in and ensure reaching bottom. Torque & drag simulations were run using Extended Reach Architect software specialized for drilling ERD wells. This innovative use of the program required creating a fictional section in the well schematic where the new BHA design was simulated. During the execution phase, the simulations proved their accuracy while pointing out the depths where the string weight is lost, and a change in pipe diameter and weight is crucial to continue running in hole. This unconventional BHA design met not only the technical requirements, but also the logistics challenges coming from the current working pipe inventory. The team looked for alternatives by designing several BHA scenarios, changing the position, amount, weight, and diameter of pipes to be used. Innovation and accurately applied well engineering created a BHA design process that unlocked the possibility to perform the completion operations of ERD horizontal wells. Ultimately 6 ERD wells were successfully prepared for fracking operations. The implementation of this BHA design workflow decreased the number of clean out runs from 5 attempts to 1 successful run in every well, therefore reducing the operational time by 12 days per well, in overall saving 75 days. Helping to bring oil production faster in Bahrain.
{"title":"One of a Kind BHA Design for ERD Wells in Bahrain","authors":"Sergio Moncayo, Sandra Szlapa, Ahmed Aljanahi, Sayed Abdelrady","doi":"10.2523/iptc-22658-ea","DOIUrl":"https://doi.org/10.2523/iptc-22658-ea","url":null,"abstract":"\u0000 An innovative BHA was designed to fit slim extended reach wellbore profiles. Precise BHA design was essential to reach the bottom of the well with a scrapper and circulate to clean the hole efficiently for enabling fracking operations with Plug & Perf technology to be performed in extended reach horizontal wells in Bahrain.\u0000 Plug & Perf operations for multistage fracking required to run plugs through a cased extended horizontal section with an internal diameter of 4\" to isolate the different stages to be stimulated. The max OD of the plug was 3.625 in leaving a marginal clearance between the plug and the casing, making hole cleaning the primary risk to deal with.\u0000 For hole cleaning it was important to design the slim BHA with a maximum OD of 3.125 in and ensure reaching bottom. Torque & drag simulations were run using Extended Reach Architect software specialized for drilling ERD wells. This innovative use of the program required creating a fictional section in the well schematic where the new BHA design was simulated. During the execution phase, the simulations proved their accuracy while pointing out the depths where the string weight is lost, and a change in pipe diameter and weight is crucial to continue running in hole.\u0000 This unconventional BHA design met not only the technical requirements, but also the logistics challenges coming from the current working pipe inventory. The team looked for alternatives by designing several BHA scenarios, changing the position, amount, weight, and diameter of pipes to be used.\u0000 Innovation and accurately applied well engineering created a BHA design process that unlocked the possibility to perform the completion operations of ERD horizontal wells. Ultimately 6 ERD wells were successfully prepared for fracking operations. The implementation of this BHA design workflow decreased the number of clean out runs from 5 attempts to 1 successful run in every well, therefore reducing the operational time by 12 days per well, in overall saving 75 days. Helping to bring oil production faster in Bahrain.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"183 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83448736","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}
Hafiz Mustafa Ud Din Sheikh, W. J. Lee, H. Jha, Sheraz Ahmed
This paper presents rigorous theoretical guidelines for durations of flow regimes for multi-fractured horizontal wells in ultra-low permeability reservoirs. Theory and practice lead us to expect four regimes: early ramp-up, transient, transition, and boundary-dominated flow (BDF) in these wells. We must model each of these flow regimes for proper forecasting and for construction of TWPs (aka type wells or type curves), but, without guidance from theory and verification in practice, the durations of these flow regimes are difficult to observe in production histories or to predict when forecasting. These forecasts have significant impact on financial decisions regarding low-permeability reservoir development. We can most readily identify flow regimes using log-log plots of pressure-normalized rate vs. time for wells produced at near-constant bottom-hole pressure. This is adequate to determine the start and end of transient flow, with a straight line whose slope is near −1/2. Diagnosis is enhanced if we add normalized rate vs. material-balance time plots, which transform the well response to an equivalent constant-rate profile, on which we can identify BDF with a straight line with −1 slope. On this plot, the transition flow regime lies between the end of transient flow and the start of BDF. In some wells, with relatively longer production histories, we can readily identify these flow regimes, but many if not most wells in a play will display neither transition nor BDF regimes. To fill this gap in knowledge, we simulated flow histories using analytical solutions, which provide shapes and durations of the flow regimes. Starts and ends of flow regimes depend on arbitrary assumptions about deviations from straight lines, which can be determined in theory using derivatives of the analytical solutions. In practice, wells do not follow theory exactly by any means, but we find in our examination of actual well production histories that theory provides excellent guidance that enhances our understanding of actual production profiles. We present our simulated production histories for wells in terms of dimensionless variables, which generalizes their applicability. For actual situations, with known or estimated reservoir and completion properties, we can use these plots of dimensionless variables to determine approximate durations of flow regimes. Importantly, for the common situation in which no production data are available beyond transient flow, we can estimate the shape of the remaining production profile in a way significantly superior to the common two-segment Arps decline model with an assumed terminal decline rate at an assumed time. Critics of the industry, particularly in the financial community, have suggested that this common approach leads to optimistic production forecasts. Realistic forecasts of production profiles for individual wells, which our workflow based on rigorous theory enhances, can improve the credibility of resource evaluators
{"title":"Establishing Flow Regimes for Multi-Fractured Horizontal Wells in Low-Permeability Reservoirs","authors":"Hafiz Mustafa Ud Din Sheikh, W. J. Lee, H. Jha, Sheraz Ahmed","doi":"10.2523/iptc-22694-ms","DOIUrl":"https://doi.org/10.2523/iptc-22694-ms","url":null,"abstract":"\u0000 This paper presents rigorous theoretical guidelines for durations of flow regimes for multi-fractured horizontal wells in ultra-low permeability reservoirs. Theory and practice lead us to expect four regimes: early ramp-up, transient, transition, and boundary-dominated flow (BDF) in these wells. We must model each of these flow regimes for proper forecasting and for construction of TWPs (aka type wells or type curves), but, without guidance from theory and verification in practice, the durations of these flow regimes are difficult to observe in production histories or to predict when forecasting. These forecasts have significant impact on financial decisions regarding low-permeability reservoir development.\u0000 We can most readily identify flow regimes using log-log plots of pressure-normalized rate vs. time for wells produced at near-constant bottom-hole pressure. This is adequate to determine the start and end of transient flow, with a straight line whose slope is near −1/2. Diagnosis is enhanced if we add normalized rate vs. material-balance time plots, which transform the well response to an equivalent constant-rate profile, on which we can identify BDF with a straight line with −1 slope. On this plot, the transition flow regime lies between the end of transient flow and the start of BDF. In some wells, with relatively longer production histories, we can readily identify these flow regimes, but many if not most wells in a play will display neither transition nor BDF regimes. To fill this gap in knowledge, we simulated flow histories using analytical solutions, which provide shapes and durations of the flow regimes. Starts and ends of flow regimes depend on arbitrary assumptions about deviations from straight lines, which can be determined in theory using derivatives of the analytical solutions. In practice, wells do not follow theory exactly by any means, but we find in our examination of actual well production histories that theory provides excellent guidance that enhances our understanding of actual production profiles.\u0000 We present our simulated production histories for wells in terms of dimensionless variables, which generalizes their applicability. For actual situations, with known or estimated reservoir and completion properties, we can use these plots of dimensionless variables to determine approximate durations of flow regimes. Importantly, for the common situation in which no production data are available beyond transient flow, we can estimate the shape of the remaining production profile in a way significantly superior to the common two-segment Arps decline model with an assumed terminal decline rate at an assumed time. Critics of the industry, particularly in the financial community, have suggested that this common approach leads to optimistic production forecasts.\u0000 Realistic forecasts of production profiles for individual wells, which our workflow based on rigorous theory enhances, can improve the credibility of resource evaluators ","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91176342","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}
The valve condition prognostics (VCP) system detects anomalies on high-pressure pump fluid-end valves and seats during fracturing before a total functional failure occurs. The VCP enables condition-based fluid-end replacement instead of time-based maintenance intervals, thereby minimizing downtime and maintenance cost and increasing asset utilization while eliminating permanent fluid-end damage due to operating with leaky valves. This is a step change when compared to the fixed-interval maintenance system. The VCP includes the programmable logic controller (PLC), analog and digital modules, a rotation monitoring encoder connected to the power end, and pressure transducers to monitor fluid-end discharge and suction pressures. The intelligent algorithms feature robust failure prediction criteria based on machine learning [1], pattern classification [2], and adaptive algorithms, applicable to various equipment and field conditions. By obtaining ongoing and accurate pressure signatures, the VCP detects warnings and alarms that are sent to the operators in real time for action. Based on the alarms and operating parameters, the pumps can be shut down automatically to prevent damage. During multiple field tests, the VCP successfully extended usable valve life by at least 45% when compared to our current fixed-interval maintenance method. The VCP is 100% accurate in detecting a catastrophic valve failure and avoided fluid-end damage. The VCP kits are easy to install onto existing pumps using existing discharge and suction pressure sensors. The data are sent to the cloud, and high-frequency data are recorded in the PLC for detailed analysis as needed. In contrast to the common replacement approach that is based on either a scheduled time interval or when an operational failure happens, the VCP can detect and notify when an anomaly occurs and performs maintenance only when necessary. The fixed-schedule maintenance approach replaces the valves and seats in a conservative fashion regardless of their condition, often leading to waste. In the failure-based maintenance situation, equipment damage often results, leading to devastating pump shut down and expensive fluid end replacement. The VCP addresses both challenges. It not only prevents prolonged and costly equipment failures, but also reduces downtime, valve and seat parts cost, and maintenance time.
{"title":"Novel Valve Condition Prognostic System for Digitally Enabled High-Pressure Pump Maintenance","authors":"David Gerber, J. Thaduri","doi":"10.2523/iptc-22220-ea","DOIUrl":"https://doi.org/10.2523/iptc-22220-ea","url":null,"abstract":"\u0000 The valve condition prognostics (VCP) system detects anomalies on high-pressure pump fluid-end valves and seats during fracturing before a total functional failure occurs. The VCP enables condition-based fluid-end replacement instead of time-based maintenance intervals, thereby minimizing downtime and maintenance cost and increasing asset utilization while eliminating permanent fluid-end damage due to operating with leaky valves. This is a step change when compared to the fixed-interval maintenance system.\u0000 The VCP includes the programmable logic controller (PLC), analog and digital modules, a rotation monitoring encoder connected to the power end, and pressure transducers to monitor fluid-end discharge and suction pressures. The intelligent algorithms feature robust failure prediction criteria based on machine learning [1], pattern classification [2], and adaptive algorithms, applicable to various equipment and field conditions. By obtaining ongoing and accurate pressure signatures, the VCP detects warnings and alarms that are sent to the operators in real time for action. Based on the alarms and operating parameters, the pumps can be shut down automatically to prevent damage.\u0000 During multiple field tests, the VCP successfully extended usable valve life by at least 45% when compared to our current fixed-interval maintenance method. The VCP is 100% accurate in detecting a catastrophic valve failure and avoided fluid-end damage. The VCP kits are easy to install onto existing pumps using existing discharge and suction pressure sensors. The data are sent to the cloud, and high-frequency data are recorded in the PLC for detailed analysis as needed.\u0000 In contrast to the common replacement approach that is based on either a scheduled time interval or when an operational failure happens, the VCP can detect and notify when an anomaly occurs and performs maintenance only when necessary. The fixed-schedule maintenance approach replaces the valves and seats in a conservative fashion regardless of their condition, often leading to waste. In the failure-based maintenance situation, equipment damage often results, leading to devastating pump shut down and expensive fluid end replacement. The VCP addresses both challenges. It not only prevents prolonged and costly equipment failures, but also reduces downtime, valve and seat parts cost, and maintenance time.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91228447","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}
Maintaining well integrity is one of the critical factors in the oil and gas industry. It requires close monitoring during the life cycle of the well, especially in offshore fields, to maximize the well life cycle and avoid catastrophic failure. Casing and bonded cement are major components of well completion that secure oil and gas production paths from different overburden formations. However, casing leaks are a common issue that might lead to serious losses in oil and gas production, locked reserves due to formation damage, personnel injuries, and severe environmental impact. Thus, it is important to detect casing leaks in the early stages to prevent such losses, which might induce a high cost of workover operations and well suspension or abandonment. Casing leaks occur due to corrosive fluids in the formations and long-term exposure to corrosive gases. During drilling, cement is set between the casing and the different formations or between the two casings for isolation and well protection. A bad cementing job leads to the failure of well barriers, cracks, and microchannels that allow corrosive fluids to migrate, which slowly corrodes casing and tubing over time. The flow direction determines the type of casing leak, either dumping (downward) or taking (upward). However, both types have a dangerous effect depending on leak severity. The identification of casing leaks, their severity, depth, and flow direction are a crucial task. Well diagnostic using the latest advanced leak detection tools is important in deciding the most appropriate remedial actions. This paper discusses a case study in a well of the Al-Khafji offshore field, where different methodologies were utilized to identify casing leaks. It involves the use of pressure/temperature profiles through downhole memory gauges, annuli pressure surveys, well-testing operations, geochemical analysis, and conventional production logs. The approach used succeeded in identifying casing leaks, flow direction, and the accurate determination of the leak location/depth.
{"title":"Efficient and Cost-Effective Casing Leak Detection Methodology on Offshore Oil Fields","authors":"M. Al-Hamdan, A. Al-Shammari","doi":"10.2523/iptc-22574-ms","DOIUrl":"https://doi.org/10.2523/iptc-22574-ms","url":null,"abstract":"\u0000 Maintaining well integrity is one of the critical factors in the oil and gas industry. It requires close monitoring during the life cycle of the well, especially in offshore fields, to maximize the well life cycle and avoid catastrophic failure.\u0000 Casing and bonded cement are major components of well completion that secure oil and gas production paths from different overburden formations. However, casing leaks are a common issue that might lead to serious losses in oil and gas production, locked reserves due to formation damage, personnel injuries, and severe environmental impact. Thus, it is important to detect casing leaks in the early stages to prevent such losses, which might induce a high cost of workover operations and well suspension or abandonment.\u0000 Casing leaks occur due to corrosive fluids in the formations and long-term exposure to corrosive gases. During drilling, cement is set between the casing and the different formations or between the two casings for isolation and well protection. A bad cementing job leads to the failure of well barriers, cracks, and microchannels that allow corrosive fluids to migrate, which slowly corrodes casing and tubing over time. The flow direction determines the type of casing leak, either dumping (downward) or taking (upward). However, both types have a dangerous effect depending on leak severity.\u0000 The identification of casing leaks, their severity, depth, and flow direction are a crucial task. Well diagnostic using the latest advanced leak detection tools is important in deciding the most appropriate remedial actions.\u0000 This paper discusses a case study in a well of the Al-Khafji offshore field, where different methodologies were utilized to identify casing leaks. It involves the use of pressure/temperature profiles through downhole memory gauges, annuli pressure surveys, well-testing operations, geochemical analysis, and conventional production logs. The approach used succeeded in identifying casing leaks, flow direction, and the accurate determination of the leak location/depth.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90531497","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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