An offshore field is producing oil from multiple reservoirs with peripheral water injection scheme. Seawater is injected through a subsea network and wellhead towers located along the original reservoir edge. However, because its OWC has moved upward, wells from wellhead towers are too remote to inject seawater effectively, with some portion going to the aquifer rather than oil pool. Therefore, it is planned to migrate injection strategy from peripheral to mid-dip pattern. An expected risk is scaling by mixing incompatible seawater and formation water. Such risk and mitigation measures were evaluated. To achieve the objective, the following methodology was applied: 1. Scale modelling based on water chemical analysis. 2. Define scale risk envelope with three risk categories 3. Tracer dynamic reservoir simulation to track formation water, connate water, dump flood water, injection seawater and treated seawater. 4. Review the past field scale history data 5. Coreflood experiment to observe actual phenomena inside the reservoir with various parameters such as water mixing ratio, sulphate concentration, temperature and chemical inhibitor 6. Consolidate all study results, conclude field scale risk and impact of mitigation measures. Scale prediction modelling, verified by coreflood tests, found that mixing reservoir formation water and injection seawater causes a sulphate scale risk, with risk severity depending on mixing ratio and sulphate concentration. Reservoir temperature was also found to correlate strongly with scale risk. Therefore, each reservoir should have different water management strategy. Scale impact is limited in the shallower wide reservoir with cooler reservoir temperature. Such reservoir should therefore have mid-dip pattern water injection to avoid low water injection efficiency with possible scale inhibitor squeezing as a contingency option. On the other hand, deeper reservoir has higher risk of scaling due to its higher temperature, causing scale plugging easily in reservoir pores and production wells. For such reservoir, peripheral aquifer water injection, treated low-sulphate seawater with sulphate-removal system, or no water injection development concept should be selected. By using modelling and experiment to quantify the scale risk over a range of conditions, the field operator has identified opportunities to optimize the water injection strategy. The temperature dependence of the scale risk means, in principal, that different injection strategy for each reservoir can minimize flow assurance challenges and maximize return on investment in scale mitigation measures.
{"title":"Water Compatibility and Scale Risk Evaluation by Integrating Scale Prediction of Fluid Modelling, Reservoir Simulation and Laboratory Coreflood Experiment for a Giant Oil Field in Offshore Abu Dhabi","authors":"Y. Nomura, M. Almarzooqi, K. Makishima, Jon Tuck","doi":"10.2118/207319-ms","DOIUrl":"https://doi.org/10.2118/207319-ms","url":null,"abstract":"\u0000 An offshore field is producing oil from multiple reservoirs with peripheral water injection scheme. Seawater is injected through a subsea network and wellhead towers located along the original reservoir edge. However, because its OWC has moved upward, wells from wellhead towers are too remote to inject seawater effectively, with some portion going to the aquifer rather than oil pool. Therefore, it is planned to migrate injection strategy from peripheral to mid-dip pattern. An expected risk is scaling by mixing incompatible seawater and formation water. Such risk and mitigation measures were evaluated.\u0000 To achieve the objective, the following methodology was applied: 1. Scale modelling based on water chemical analysis. 2. Define scale risk envelope with three risk categories 3. Tracer dynamic reservoir simulation to track formation water, connate water, dump flood water, injection seawater and treated seawater. 4. Review the past field scale history data 5. Coreflood experiment to observe actual phenomena inside the reservoir with various parameters such as water mixing ratio, sulphate concentration, temperature and chemical inhibitor 6. Consolidate all study results, conclude field scale risk and impact of mitigation measures.\u0000 Scale prediction modelling, verified by coreflood tests, found that mixing reservoir formation water and injection seawater causes a sulphate scale risk, with risk severity depending on mixing ratio and sulphate concentration. Reservoir temperature was also found to correlate strongly with scale risk. Therefore, each reservoir should have different water management strategy. Scale impact is limited in the shallower wide reservoir with cooler reservoir temperature. Such reservoir should therefore have mid-dip pattern water injection to avoid low water injection efficiency with possible scale inhibitor squeezing as a contingency option. On the other hand, deeper reservoir has higher risk of scaling due to its higher temperature, causing scale plugging easily in reservoir pores and production wells. For such reservoir, peripheral aquifer water injection, treated low-sulphate seawater with sulphate-removal system, or no water injection development concept should be selected.\u0000 By using modelling and experiment to quantify the scale risk over a range of conditions, the field operator has identified opportunities to optimize the water injection strategy. The temperature dependence of the scale risk means, in principal, that different injection strategy for each reservoir can minimize flow assurance challenges and maximize return on investment in scale mitigation measures.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"61 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74406504","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}
Arabian Gulf region with its hot, humid and prolonged summer is known to be one of the most challenging environments for radio-wave propagation. Over-the-sea microwave radio links here face degradation and unpredictability in performance due to anomalous propagation, ducting and reflective effects of large water bodies. This paper presents microwave radio link design challenges in an offshore environment and the methods implemented to overcome these challenges in the context of specific project experience in offshore field areas. A baseline design for the links was established initially which was optimized during the course of the project and during on-site implementation. Several design changes to achieve the desired performance were evaluated and implemented in the field. Required microwave link availability and performance objectives were achieved as a result of collaborative efforts between the operating company, contractor and radio manufacturer over a multi-year period. Use of quadruple diversity, optimal selection of frequencies, judicious use of ATPC (Automatic Transmit Power Control) and use of optimal signal polarisation were some of the methods used to achieve the desired link availability and performance. While these are well-known methods in radio engineering, the particular combination(s) employed to realize the desired performance objectives are identified in the paper as a lessons-learnt exercise which can be of wider application in the petroleum industry in the Gulf region. Over-water wideband microwave links are generally considered unreliable in terms of performance for utilization in process control applications involving remote shutdown and other critical operations. However, the links referred to in this paper continue to serve the field control system applications till date.
{"title":"Design Considerations for Over-Water Microwave Radio Links - A Case Study","authors":"Yunus Chozhiyattel, Iman Affan","doi":"10.2118/207630-ms","DOIUrl":"https://doi.org/10.2118/207630-ms","url":null,"abstract":"\u0000 Arabian Gulf region with its hot, humid and prolonged summer is known to be one of the most challenging environments for radio-wave propagation. Over-the-sea microwave radio links here face degradation and unpredictability in performance due to anomalous propagation, ducting and reflective effects of large water bodies. This paper presents microwave radio link design challenges in an offshore environment and the methods implemented to overcome these challenges in the context of specific project experience in offshore field areas.\u0000 A baseline design for the links was established initially which was optimized during the course of the project and during on-site implementation. Several design changes to achieve the desired performance were evaluated and implemented in the field. Required microwave link availability and performance objectives were achieved as a result of collaborative efforts between the operating company, contractor and radio manufacturer over a multi-year period.\u0000 Use of quadruple diversity, optimal selection of frequencies, judicious use of ATPC (Automatic Transmit Power Control) and use of optimal signal polarisation were some of the methods used to achieve the desired link availability and performance. While these are well-known methods in radio engineering, the particular combination(s) employed to realize the desired performance objectives are identified in the paper as a lessons-learnt exercise which can be of wider application in the petroleum industry in the Gulf region. Over-water wideband microwave links are generally considered unreliable in terms of performance for utilization in process control applications involving remote shutdown and other critical operations. However, the links referred to in this paper continue to serve the field control system applications till date.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"61 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83119573","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Jaya, Ghazali Ahmad Riza, Ahmad Fuad M. Izzuljad, Mad Sahad Salbiah
The prediction of fluid parameter related to hydrocarbon presence using seismic data has often been limited by the performance of probability density function in estimating fluid properties from seismic inversion results. A novel fluid bulk modulus inversion (fBMI) is a pre-stack seismic inversion technique that has been developed to allow a direct estimation of pore fluid bulk modulus (Kf) from seismic data. Real data application in Malay basin showcases that Kf volume can be used to pinpoint areas with high probability of hydrocarbon presence. The fluid term AVO reflectivity (Russell et al., 2011) is used as the basis of our formulation and has been extended to allow direct estimation of pore fluid bulk modulus, shearmodulus, porosity parameter and density through standard least-square inversion. The novel formulation is able to relax the dependency of fluid terms on the porosity. To demonstrate this, verifications were made against standard linear AVO approximations. Our observation shows that the young tertiary basins such as the Malay basin the fluid bulk modulus values have a big contrast between hydrocarbon saturated and water bearing reservoirs with a minimum of 60% ratio difference. The inverted fluid bulk modulus volume provides thus a direct assessment of areas with high probability of hydrocarbon saturation. In this paper, the fBMI technique is showcased on a field in the Malay basin. The outcome is demonstrated on a well panel analysis for four wells located across the study area (Figure 1). The inverted fluid bulk modulus extracted along a horizon representing the top of target reservoir is shown in Figure 2b. The blue color indicates high bulk modulus corresponds to water-bearing zone, while the yellow-red color range corresponding to low hydrocarbon-bearing zones. The areas of low fluid bulk modulus values at the north-western region are calibrated to known production zones in that region. fBMI shows areas that delineate high probability of hydrocarbon presence and provides a quantitative measure in terms of fluid parameter directly related to the presence of hydrocarbon saturations. Figure 1: Comparison analysis of water saturation (blue curve) and fluid bulk modulus (red curve) of well log data in the Malay basin. Black strips indicate the coal intervals. Figure 2: a) Inverted acoustic impedance extracted from the top reservoir horizon of a field in the Malay basin. b) The corresponding fluid bulk modulus values from fBMI. The fBMI is a new four parameters linear amplitude-versus-offset inversion technique that provides quantitative fluid parameter directly related to fluid bulk modulus from seismic data. It is utilized as a tool for direct hydrocarbon prospect assessment to differentiate gas, oil, condensate and water.
利用地震资料预测与油气存在相关的流体参数，往往受到地震反演结果估计流体性质时概率密度函数性能的限制。一种新型流体体积模量反演(fBMI)是一种叠前地震反演技术，可以从地震数据中直接估计孔隙流体体积模量(Kf)。在马来盆地的实际数据应用表明，Kf体积可以用来确定油气存在的高可能性区域。流体项AVO反射率(Russell et al.， 2011)作为我们公式的基础，并进行了扩展，可以通过标准最小二乘反演直接估计孔隙流体体积模量、剪切模量、孔隙度参数和密度。新配方能够减轻流体项对孔隙度的依赖。为了证明这一点，对标准线性AVO近似进行了验证。研究表明，马来盆地等年轻第三系盆地的流体体积模量在含水与饱和储层之间存在较大的对比，比差最小可达60%。因此，倒置的流体体积模量可以直接评估油气饱和度高的区域。本文以马来盆地某油田为例，介绍了fBMI技术。通过对研究区域内4口井的面板分析，结果得到了验证(图1)。图2b显示了沿目标储层顶部的水平面提取的反向流体体积模量。蓝色表示高体积模量对应含水区，而黄红色表示低含油区。将西北地区流体体积模数值较低的区域校准为该地区已知的生产区域。fBMI显示了烃存在的高可能性区域，并提供了与烃饱和度存在直接相关的流体参数的定量测量。图1马来盆地测井资料含水饱和度(蓝色曲线)与流体体积模量(红色曲线)对比分析黑色条表示煤间隔。图2:a)马来盆地某油田顶部储层反演声阻抗图。b)由fBMI得到的相应流体体积模量值。fBMI是一种新的四参数线性振幅-偏移反演技术，可以从地震数据中提供与流体体积模量直接相关的定量流体参数。将其作为油气远景直接评价的工具，用于区分气、油、凝析油和水。
{"title":"Accurate Pore Fluid Indicator Prediction Using Seismic Fluid Bulk Modulus Inversion","authors":"M. Jaya, Ghazali Ahmad Riza, Ahmad Fuad M. Izzuljad, Mad Sahad Salbiah","doi":"10.2118/208174-ms","DOIUrl":"https://doi.org/10.2118/208174-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The prediction of fluid parameter related to hydrocarbon presence using seismic data has often been limited by the performance of probability density function in estimating fluid properties from seismic inversion results. A novel fluid bulk modulus inversion (fBMI) is a pre-stack seismic inversion technique that has been developed to allow a direct estimation of pore fluid bulk modulus (Kf) from seismic data. Real data application in Malay basin showcases that Kf volume can be used to pinpoint areas with high probability of hydrocarbon presence.\u0000 \u0000 \u0000 \u0000 The fluid term AVO reflectivity (Russell et al., 2011) is used as the basis of our formulation and has been extended to allow direct estimation of pore fluid bulk modulus, shearmodulus, porosity parameter and density through standard least-square inversion. The novel formulation is able to relax the dependency of fluid terms on the porosity. To demonstrate this, verifications were made against standard linear AVO approximations. Our observation shows that the young tertiary basins such as the Malay basin the fluid bulk modulus values have a big contrast between hydrocarbon saturated and water bearing reservoirs with a minimum of 60% ratio difference. The inverted fluid bulk modulus volume provides thus a direct assessment of areas with high probability of hydrocarbon saturation.\u0000 \u0000 \u0000 \u0000 In this paper, the fBMI technique is showcased on a field in the Malay basin. The outcome is demonstrated on a well panel analysis for four wells located across the study area (Figure 1). The inverted fluid bulk modulus extracted along a horizon representing the top of target reservoir is shown in Figure 2b. The blue color indicates high bulk modulus corresponds to water-bearing zone, while the yellow-red color range corresponding to low hydrocarbon-bearing zones. The areas of low fluid bulk modulus values at the north-western region are calibrated to known production zones in that region. fBMI shows areas that delineate high probability of hydrocarbon presence and provides a quantitative measure in terms of fluid parameter directly related to the presence of hydrocarbon saturations. Figure 1: Comparison analysis of water saturation (blue curve) and fluid bulk modulus (red curve) of well log data in the Malay basin. Black strips indicate the coal intervals. Figure 2: a) Inverted acoustic impedance extracted from the top reservoir horizon of a field in the Malay basin. b) The corresponding fluid bulk modulus values from fBMI.\u0000 \u0000 \u0000 \u0000 The fBMI is a new four parameters linear amplitude-versus-offset inversion technique that provides quantitative fluid parameter directly related to fluid bulk modulus from seismic data. It is utilized as a tool for direct hydrocarbon prospect assessment to differentiate gas, oil, condensate and water.\u0000","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81424667","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}
Gaojing Cao, Xiangzen Wang, Lei Nie, Yaoqiang Hu, Yundong Xie, Gayatri P. Kartoatmodjo, Paul Williams, R. Henson, M. Zhu, Andrew Fendt, Lang Wang, Carlos Sanita
In the era of all-encompassing Big Data and the Internet of Things (IoT), mastery of Instrument Control (I&C) and SCADA systems deployment is becoming more important as the Operational Technology (OT) foundation for digital integration, data gathering, processing, analytics, and the optimization of business results. Integration and communication between different I&C and SCADA products and systems in an Oil and Gas project represent a significant challenge. The issues encountered on projects globally can prolong project schedules from weeks to months with consequential impacts on commercial gas production, project cash flow, and economics. This paper presents how to enable digital operations through holistic design, well-organized kickoff, effective Integrated Factory Acceptance Test (IFAT), and timely commissioning of I&C and SCADA systems for surface facilities of a gas field development project. It provides a feasible, economical and proven solution to address the foregoing challenges. Furthermore, in this paper we present a snapshot of how to use the latest data-science technology to bring out the value of the gold mine - big data generated by the I&C and SCADA systems.
{"title":"Digital Enablement Through Effective Deployment and Commissioning of Instrumentation, Supervisory Control and Data Acquisition System SCADA in Surface Facilities","authors":"Gaojing Cao, Xiangzen Wang, Lei Nie, Yaoqiang Hu, Yundong Xie, Gayatri P. Kartoatmodjo, Paul Williams, R. Henson, M. Zhu, Andrew Fendt, Lang Wang, Carlos Sanita","doi":"10.2118/208210-ms","DOIUrl":"https://doi.org/10.2118/208210-ms","url":null,"abstract":"\u0000 In the era of all-encompassing Big Data and the Internet of Things (IoT), mastery of Instrument Control (I&C) and SCADA systems deployment is becoming more important as the Operational Technology (OT) foundation for digital integration, data gathering, processing, analytics, and the optimization of business results.\u0000 Integration and communication between different I&C and SCADA products and systems in an Oil and Gas project represent a significant challenge. The issues encountered on projects globally can prolong project schedules from weeks to months with consequential impacts on commercial gas production, project cash flow, and economics.\u0000 This paper presents how to enable digital operations through holistic design, well-organized kickoff, effective Integrated Factory Acceptance Test (IFAT), and timely commissioning of I&C and SCADA systems for surface facilities of a gas field development project. It provides a feasible, economical and proven solution to address the foregoing challenges. Furthermore, in this paper we present a snapshot of how to use the latest data-science technology to bring out the value of the gold mine - big data generated by the I&C and SCADA systems.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82008712","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Jaya, Abdrahman Sharif, Ali Ahmed Reda Abdulkarim, Ghazali Ahmad Riza, Maleki Ali Hajian, Elsebakhi Emad
The performance of ML-based rock properties prediction from seismic with limited and sparse well data is very often inadequate. To address this limitation, we propose a novel automatic well log regularization (ALR) method with specially designed feature augmentation strategy to improve the prediction accuracy. The effectiveness of ALR method is showcased on field data in Malay basin where we successfully predict elastic logs with 30% higher accuracy, while using only 28% less training dataset. The ALR workflow (Figure 1): (1) feature selection and augmentation; (2) training and prediction and (3) prediction optimizations. The workflow starts with predicting any logs type which are available at training but not in blind wells using standard ML workflow for all blind wells (Step 1-2). Then, these intermediately predicted logs at blind well were jointly used as input features together with seismic-derived attributes using a specially designed feature augmentation strategy (Step 3). Finally, Step 1and 2 are then repeated to predict the elastic logs using these augmented input features. The ALR method was applied on an oil/gas field data in Malay basin to predict elastic logs (AI and SI) at five blind wells from seismic data only and compared to the standard ML workflow. Two wells were used as training (28% of all data). The prediction performance of standard ML workflow (Figure 2a) is poor and can only capture general mean values of the actual AI/SI logs. The results of ALR workflow (Figure 2b) shows 30% better prediction performance compared to the standard ML workflow. In general, the background and high-resolution trend are well captured, and the overall prediction performance is improved using the new proposed prediction method. There are conceivably two explanations for this result: a) the background (low frequency) trend of the well log is properly reconstructed in ALR using only using seismic data. This could mainly lie in the ability of augmented features in better learning the uncertain reflection-reception relationship between seismic data and elastic logs, as well as the spatial/time-varying property of seismic data; (b) The ability to learn meaningful nonlinear feature relationship between input (feature) and output (label) variables with little or no supervision seems to work properly using specially designed feature augmentation. The ALR method is an ML-based pseudo log generation from seismic data using specially designed feature augmentation strategy. The novel ALR implementation relaxes the requirement of having a massive amount of high-quality labeled data for training and can therefore be applied in areas with limited well data information. ALR method is proven to be highly accurate for direct elastic logs prediction and can potentially be extended to estimate petrophysical properties from seismic data.
{"title":"Accurate Pseudo Log Prediction Using Machine Learning Based Automatic Log Regularization and Feature Augmentation Method","authors":"M. Jaya, Abdrahman Sharif, Ali Ahmed Reda Abdulkarim, Ghazali Ahmad Riza, Maleki Ali Hajian, Elsebakhi Emad","doi":"10.2118/207230-ms","DOIUrl":"https://doi.org/10.2118/207230-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The performance of ML-based rock properties prediction from seismic with limited and sparse well data is very often inadequate. To address this limitation, we propose a novel automatic well log regularization (ALR) method with specially designed feature augmentation strategy to improve the prediction accuracy. The effectiveness of ALR method is showcased on field data in Malay basin where we successfully predict elastic logs with 30% higher accuracy, while using only 28% less training dataset.\u0000 \u0000 \u0000 \u0000 The ALR workflow (Figure 1): (1) feature selection and augmentation; (2) training and prediction and (3) prediction optimizations. The workflow starts with predicting any logs type which are available at training but not in blind wells using standard ML workflow for all blind wells (Step 1-2). Then, these intermediately predicted logs at blind well were jointly used as input features together with seismic-derived attributes using a specially designed feature augmentation strategy (Step 3). Finally, Step 1and 2 are then repeated to predict the elastic logs using these augmented input features.\u0000 \u0000 \u0000 \u0000 The ALR method was applied on an oil/gas field data in Malay basin to predict elastic logs (AI and SI) at five blind wells from seismic data only and compared to the standard ML workflow. Two wells were used as training (28% of all data). The prediction performance of standard ML workflow (Figure 2a) is poor and can only capture general mean values of the actual AI/SI logs. The results of ALR workflow (Figure 2b) shows 30% better prediction performance compared to the standard ML workflow. In general, the background and high-resolution trend are well captured, and the overall prediction performance is improved using the new proposed prediction method. There are conceivably two explanations for this result: a) the background (low frequency) trend of the well log is properly reconstructed in ALR using only using seismic data. This could mainly lie in the ability of augmented features in better learning the uncertain reflection-reception relationship between seismic data and elastic logs, as well as the spatial/time-varying property of seismic data; (b) The ability to learn meaningful nonlinear feature relationship between input (feature) and output (label) variables with little or no supervision seems to work properly using specially designed feature augmentation.\u0000 \u0000 \u0000 \u0000 The ALR method is an ML-based pseudo log generation from seismic data using specially designed feature augmentation strategy. The novel ALR implementation relaxes the requirement of having a massive amount of high-quality labeled data for training and can therefore be applied in areas with limited well data information. ALR method is proven to be highly accurate for direct elastic logs prediction and can potentially be extended to estimate petrophysical properties from seismic data.\u0000","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86930624","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}
Christna Golaco, Siddharth Jain, Shams Obaid, Faisal Al Nakeeb
Sharjah National Oil Corporation (SNOC) operates 4 onshore gas condensate reservoirs of which 3 are very mature consisting of 50+ wells producing corrosive hydrocarbons for over 30 years. The integrity of these legacy wells is frequently questioned before any development is conceptualized, thus making it critical to evaluate the well integrity. The cost associated with pulling completions for their evaluation and running logs in all wells is significant and the availability of various emerging technologies for corrosion analysis in the market makes it challenging to choose the most reliable one. This paper focuses on the detailed analysis and comparison of electromagnetic thickness logs run in 10% of the well stock from 2016 to post-workover surface inspection of the downhole recovered tubing's in 2020/21. It also quantifies how correlating different logging technologies for well integrity increases the reliability of the electromagnetic technology applied on offset wells. The paper also showcases a comparison between mechanical and electromagnetic thickness evaluation of the production casing in-situ. Data from all the available logs from past 5 years was compiled for 6 wells. On recovery of the downhole completion tubings via a hydraulic workover, an ultrasonic (UT) inspection was performed on them at surface. Both sets of results (logs and surface inspection) were analyzed on the same logging track to give a comprehensive comparison of actual observation on surface vs the measurement by in-situ logging. Another multi-barrier corrosion and caliper log were run in the production casing to analyze their outcomes alongside older results. The final step was a comparison of all available data to create a broad well integrity profile. It was observed that the remaining production tubing metal thickness detected by electromagnetic tool (logs) and surface ultrasonic measurements were in good conformance (+/-10%). In the corrosion evaluation of the production casing, the electromagnetic tool matched extremely well with the caliper log results. This shows a large reliability of this technology to quantify corrosion in offset wells. The correlation of logs with surface inspection results across wells in the same reservoir did not indicate a strong presence of external corrosion. The study enables the management to make critical business decisions on utilizing the well stock for the future. This work is the first time a comprehensive and critical analysis on the electromagnetic thickness logging technology has been done, comparing their results of remaining wall thickness to various technologies in-situ and on surface. The analysis not only compares technology from various providers, but also mechanical vs electromagnetic measurements along with their respective advantages in quantifying well integrity assurance. The paper also gives an idea on the condition of L-80 tubulars under service for 30+ years.
{"title":"Generating Value from Mature Gas Fields by Quantifying Well Integrity Assurance with a Critical Analysis of Multiple Logs & Retrieved Tubular Surface Inspection","authors":"Christna Golaco, Siddharth Jain, Shams Obaid, Faisal Al Nakeeb","doi":"10.2118/208204-ms","DOIUrl":"https://doi.org/10.2118/208204-ms","url":null,"abstract":"\u0000 Sharjah National Oil Corporation (SNOC) operates 4 onshore gas condensate reservoirs of which 3 are very mature consisting of 50+ wells producing corrosive hydrocarbons for over 30 years. The integrity of these legacy wells is frequently questioned before any development is conceptualized, thus making it critical to evaluate the well integrity. The cost associated with pulling completions for their evaluation and running logs in all wells is significant and the availability of various emerging technologies for corrosion analysis in the market makes it challenging to choose the most reliable one.\u0000 This paper focuses on the detailed analysis and comparison of electromagnetic thickness logs run in 10% of the well stock from 2016 to post-workover surface inspection of the downhole recovered tubing's in 2020/21. It also quantifies how correlating different logging technologies for well integrity increases the reliability of the electromagnetic technology applied on offset wells. The paper also showcases a comparison between mechanical and electromagnetic thickness evaluation of the production casing in-situ.\u0000 Data from all the available logs from past 5 years was compiled for 6 wells. On recovery of the downhole completion tubings via a hydraulic workover, an ultrasonic (UT) inspection was performed on them at surface. Both sets of results (logs and surface inspection) were analyzed on the same logging track to give a comprehensive comparison of actual observation on surface vs the measurement by in-situ logging. Another multi-barrier corrosion and caliper log were run in the production casing to analyze their outcomes alongside older results. The final step was a comparison of all available data to create a broad well integrity profile.\u0000 It was observed that the remaining production tubing metal thickness detected by electromagnetic tool (logs) and surface ultrasonic measurements were in good conformance (+/-10%). In the corrosion evaluation of the production casing, the electromagnetic tool matched extremely well with the caliper log results. This shows a large reliability of this technology to quantify corrosion in offset wells. The correlation of logs with surface inspection results across wells in the same reservoir did not indicate a strong presence of external corrosion. The study enables the management to make critical business decisions on utilizing the well stock for the future.\u0000 This work is the first time a comprehensive and critical analysis on the electromagnetic thickness logging technology has been done, comparing their results of remaining wall thickness to various technologies in-situ and on surface. The analysis not only compares technology from various providers, but also mechanical vs electromagnetic measurements along with their respective advantages in quantifying well integrity assurance. The paper also gives an idea on the condition of L-80 tubulars under service for 30+ years.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89419739","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}
Mubashir Mubashir Ahmad, Ayman El Shahat, M. O. El-Meguid, Ali Sulaiman Bin Sumaida, Hessa Mohammed Al Shehhi, Fawad Zain Yousfi, M. Albadi, Ibrahim Al Mansouri, T. Solaiman, M. Baslaib, S. Alhouqani, Mariam M. Al Reyami, A. Gadelhak, A. Shaker, A. Alsaeedi, M. Elabrashy, M. Alzeyoudi, S. Alsenaidi, Bakheeta Al Muhairi, E. Al Mheiri, Omar Al Jeelani, Noora Al Maria, Mahmoud A Basioni, S. Sayed, Ahmed Yahya Al Blooshi, Ahmed Mahmoud Elmahdi, Ali Al Mansoori, Jasim Ali Alloghani
Deepest Deviated Appraisal well in Upper Khuff reservoir in a small artificial island, located about 100 KM away from Abu Dhabi shore was successfully drilled and tested. The well has been recognized as the deepest deviated well on offshore Island with highest bottom hole reservoir temperature in UAE about 375 deg F (190 degrees C) and exceeding 9000 psi reservoir pressure complemented with impurities of H2S ranging from 10-22% and CO2 between 9-20%. The challenges were immense, from designing to execution, including securing special materials for the unique well design to accommodate the sour environment of Khuff reservoir as exploring new reservoirs always counter many risks comparing to developed reservoirs. The execution was driven with the focus of maximizing the ultimate value and benefit for ADNOC, our respected partners, the community and the UAE. The field is located in the most sensitive and ecological important area and is under UNESCO Biosphere reserve. The appraisal well was successfully drilled to Khuff reservoir at a depth of 19000 ft. The well test using Drill stem test (DST string) was conducted. Multiple challenges ranging from HSE, material selection, drilling and logging tools availability, limitations and procuring them in time were overcome by utilizing the World First Integrated Zero Waste Discharge Solution in Restricted & Highly Environmentally Sensitive Areas. Another major challenge faced during the drilling deeper reservoir was mud rheology changes due to high temperatures. The logging program was tailored to overcome the challenges posed by the mud, high temperature, high pressure, sour condition and to gain maximum representative reservoir data in a reservoir where high-pressure steaks and geological unconformities were anticipated. The Drill stem test, (DST) string was successfully POOH after acquiring all the objectives from Khuff K-4 testing under above mentioned harsh environment. The zonal isolation was carried out with cement and rig was released. The drilling and testing operation was conducted with high level of cooperation and excellence accomplishing the well set objectives without (Lost Time Injury). Lessons learned are widely shared with all the teams across the region to expedite and improve on the technologies used for sour gas production. ADNOC Onshore demonstrated 100% HSE, full commitment, high collaboration and efficient outcome ensuring safety compliance for the successful delivery of this highly critical project. This paper presents the various challenges faced and overcome while carrying out the Drilling and testing of the HPHT Sour well offshore.
{"title":"Deepest Deviated HPHT Gas Well Drilling and Testing Challenges in an Offshore Island Case-study","authors":"Mubashir Mubashir Ahmad, Ayman El Shahat, M. O. El-Meguid, Ali Sulaiman Bin Sumaida, Hessa Mohammed Al Shehhi, Fawad Zain Yousfi, M. Albadi, Ibrahim Al Mansouri, T. Solaiman, M. Baslaib, S. Alhouqani, Mariam M. Al Reyami, A. Gadelhak, A. Shaker, A. Alsaeedi, M. Elabrashy, M. Alzeyoudi, S. Alsenaidi, Bakheeta Al Muhairi, E. Al Mheiri, Omar Al Jeelani, Noora Al Maria, Mahmoud A Basioni, S. Sayed, Ahmed Yahya Al Blooshi, Ahmed Mahmoud Elmahdi, Ali Al Mansoori, Jasim Ali Alloghani","doi":"10.2118/207506-ms","DOIUrl":"https://doi.org/10.2118/207506-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Deepest Deviated Appraisal well in Upper Khuff reservoir in a small artificial island, located about 100 KM away from Abu Dhabi shore was successfully drilled and tested.\u0000 The well has been recognized as the deepest deviated well on offshore Island with highest bottom hole reservoir temperature in UAE about 375 deg F (190 degrees C) and exceeding 9000 psi reservoir pressure complemented with impurities of H2S ranging from 10-22% and CO2 between 9-20%.\u0000 \u0000 \u0000 \u0000 The challenges were immense, from designing to execution, including securing special materials for the unique well design to accommodate the sour environment of Khuff reservoir as exploring new reservoirs always counter many risks comparing to developed reservoirs.\u0000 The execution was driven with the focus of maximizing the ultimate value and benefit for ADNOC, our respected partners, the community and the UAE. The field is located in the most sensitive and ecological important area and is under UNESCO Biosphere reserve.\u0000 \u0000 \u0000 \u0000 The appraisal well was successfully drilled to Khuff reservoir at a depth of 19000 ft. The well test using Drill stem test (DST string) was conducted.\u0000 Multiple challenges ranging from HSE, material selection, drilling and logging tools availability, limitations and procuring them in time were overcome by utilizing the World First Integrated Zero Waste Discharge Solution in Restricted & Highly Environmentally Sensitive Areas.\u0000 Another major challenge faced during the drilling deeper reservoir was mud rheology changes due to high temperatures. The logging program was tailored to overcome the challenges posed by the mud, high temperature, high pressure, sour condition and to gain maximum representative reservoir data in a reservoir where high-pressure steaks and geological unconformities were anticipated.\u0000 The Drill stem test, (DST) string was successfully POOH after acquiring all the objectives from Khuff K-4 testing under above mentioned harsh environment. The zonal isolation was carried out with cement and rig was released.\u0000 \u0000 \u0000 \u0000 The drilling and testing operation was conducted with high level of cooperation and excellence accomplishing the well set objectives without (Lost Time Injury).\u0000 Lessons learned are widely shared with all the teams across the region to expedite and improve on the technologies used for sour gas production. ADNOC Onshore demonstrated 100% HSE, full commitment, high collaboration and efficient outcome ensuring safety compliance for the successful delivery of this highly critical project.\u0000 This paper presents the various challenges faced and overcome while carrying out the Drilling and testing of the HPHT Sour well offshore.\u0000","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87528340","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}
R. Lowdon, Hiep Tien Nguyen, Mahmoud Elgizawy, Saback Victor
Wellbore surveying is a critical component of any well construction project. Understanding the position of a well in 3D space allows for the wells geological objectives to be carried out while safely avoiding other wellbores. Wellbore surveys are generally conducted using a magnetically referenced measurement while drilling tool (MWD) and taken while static, either before, after or sometimes during the connection. The drillstring is often worked to release trapped torque and time is often taken waiting for the survey to be pumped up. All of this consumes rig time and opens the wellbore up to wellbore instability issues. The application of definitive dynamic surveys (DDS) which are static MWD quality surveys taken while drilling and updated continuously. There is no longer a need to stop and take a static survey eliminating MWD surveying related rig time, reducing drilling risks from additional pumps off time and improving TVD accuracy and directional control. The rig time taken for surveying with and without DDS will be compared between similar wells in the field, and detailed analysis of relative tortuosity between DDS and non-DDS wells will also be conducted. Trajectory control analysis will be reviewed by looking at the difference in the number of downlinks between DDS and no DDS wells and also the deviation from the planned trajectory. An overall analysis of on bottom ROP will be made and an analysis as to the relative differences in TVD between static and DDS survey will be carried out. This abstract will outline the rig time and operational savings from DDS, it will detail the surveying time savings, directional control improvements, TVD placement differences to static surveys and provide costs savings as a comparison to previous similar wells. This will be outlined over a number of wells, divided by sections as the wells are batch drilled and provide an insight into the benefits of DDS on a drilling campaign. Some discussion will be made as to the efficacy of the DDS surveys and how their error model has been developed. DDS is a unique and novel way of taking surveys while drilling, providing static MWD quality without the added rig time costs but at a much higher frequency that the typical once a stand survey program. This paper outlines the cost and process savings associated with using the DDS surveys.
{"title":"Definitive Dynamic MWD Surveys Generate Rig Time Savings and Flat Time Reductions in the Middle East","authors":"R. Lowdon, Hiep Tien Nguyen, Mahmoud Elgizawy, Saback Victor","doi":"10.2118/207301-ms","DOIUrl":"https://doi.org/10.2118/207301-ms","url":null,"abstract":"\u0000 Wellbore surveying is a critical component of any well construction project. Understanding the position of a well in 3D space allows for the wells geological objectives to be carried out while safely avoiding other wellbores.\u0000 Wellbore surveys are generally conducted using a magnetically referenced measurement while drilling tool (MWD) and taken while static, either before, after or sometimes during the connection. The drillstring is often worked to release trapped torque and time is often taken waiting for the survey to be pumped up. All of this consumes rig time and opens the wellbore up to wellbore instability issues.\u0000 The application of definitive dynamic surveys (DDS) which are static MWD quality surveys taken while drilling and updated continuously. There is no longer a need to stop and take a static survey eliminating MWD surveying related rig time, reducing drilling risks from additional pumps off time and improving TVD accuracy and directional control.\u0000 The rig time taken for surveying with and without DDS will be compared between similar wells in the field, and detailed analysis of relative tortuosity between DDS and non-DDS wells will also be conducted. Trajectory control analysis will be reviewed by looking at the difference in the number of downlinks between DDS and no DDS wells and also the deviation from the planned trajectory. An overall analysis of on bottom ROP will be made and an analysis as to the relative differences in TVD between static and DDS survey will be carried out.\u0000 This abstract will outline the rig time and operational savings from DDS, it will detail the surveying time savings, directional control improvements, TVD placement differences to static surveys and provide costs savings as a comparison to previous similar wells. This will be outlined over a number of wells, divided by sections as the wells are batch drilled and provide an insight into the benefits of DDS on a drilling campaign. Some discussion will be made as to the efficacy of the DDS surveys and how their error model has been developed.\u0000 DDS is a unique and novel way of taking surveys while drilling, providing static MWD quality without the added rig time costs but at a much higher frequency that the typical once a stand survey program. This paper outlines the cost and process savings associated with using the DDS surveys.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87425513","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}
Sawsan M. Ali, MEng, CEng, MIChemE, Santhanam Thyagarajan, Ashwani Kataria, Sami Al Ankar, Amal Al Marzooqi
Numerous CO2 injection pipeline applications have been developed and implemented in the past decades in the UAE and all around the globe. Transporting the CO2 in dense phase, rather than in gas or liquid phases, is well recognized of being techno-economically attractive with respect to its major CAPEX benefits of optimized pipeline material of construction; which is driven by the high water solubility in dense phase CO2 as well as the optimized pipeline size which is greatly influenced by the density and viscosity characteristics of supercritical/dense phase CO2. In light of the active deployment of dense phase CO2 injection EOR pipeline transportation across the various existing and future CO2 capture facilities across the UAE, ADNOC onshore technical expertise team has been conducting intensive research analysis on the unique thermodynamic aspects of dense phase CO2 pipeline systems. The focus was directed towards understanding the transient characteristics, which directly influence crucial design strategies including and not limited to CO2 purity specifications, CO2 pipeline pressure and temperature operating envelopes as well as the developed operating philosophy which involves start-up, shutdown and depressurization. While optimizing the economics of the carbon capture units (CCUS) is a pivotal strategy mandating rationalizing the dictated purity level of the captured CO2 and valorizing the projects. However, such thrifty initiatives to moderate the costs of the selected CO2 removal technologies can lead to underlying cascading effects of the lower purity recovered CO2 on systems design and its operation. As part of the nation's strategic objective to reduce carbon footprint, CO2 has been recovered for EOR re-injection applications. Relaxing the purity specification met by the CO2 capture units can positively improve the cost of the recovery plant while may potentially have adverse impacts on CO2 pipeline integrity. This paper provides a comprehensive analysis of the impact of the CO2 purity specification on the flow assurance safety performance of dense phase CO2 pipeline. It is worth highlighting that the design of CO2 systems is challenged by the paucity of the available reference design guidelines since domain of CO2 itself is still evolving under an active area of research. Although some previous publications have demonstrated the latent underlying effects of imputiries such as (N2, H2, SO2, NO2, CH4, C2H6, and Argon) on the physical and thermodynamic behavior of CO2 systems, however, this was supported by literature experimental modelling without transient analysis. In this paper, the behavior of varying CO2 purity levels on the design and operational aspects of CO2 pipeline is substantiated and both steady state and transient flow assurance modelling are presented. Gauging the system's design integrity cannot be solely assured from the perspective of steady state behavior and hence this paper's findings provide additional infor
{"title":"Impact of CCUS Impurities on Dense Phase CO2 Pipeline Surface Engineering Design","authors":"Sawsan M. Ali, MEng, CEng, MIChemE, Santhanam Thyagarajan, Ashwani Kataria, Sami Al Ankar, Amal Al Marzooqi","doi":"10.2118/207354-ms","DOIUrl":"https://doi.org/10.2118/207354-ms","url":null,"abstract":"\u0000 Numerous CO2 injection pipeline applications have been developed and implemented in the past decades in the UAE and all around the globe. Transporting the CO2 in dense phase, rather than in gas or liquid phases, is well recognized of being techno-economically attractive with respect to its major CAPEX benefits of optimized pipeline material of construction; which is driven by the high water solubility in dense phase CO2 as well as the optimized pipeline size which is greatly influenced by the density and viscosity characteristics of supercritical/dense phase CO2.\u0000 In light of the active deployment of dense phase CO2 injection EOR pipeline transportation across the various existing and future CO2 capture facilities across the UAE, ADNOC onshore technical expertise team has been conducting intensive research analysis on the unique thermodynamic aspects of dense phase CO2 pipeline systems. The focus was directed towards understanding the transient characteristics, which directly influence crucial design strategies including and not limited to CO2 purity specifications, CO2 pipeline pressure and temperature operating envelopes as well as the developed operating philosophy which involves start-up, shutdown and depressurization.\u0000 While optimizing the economics of the carbon capture units (CCUS) is a pivotal strategy mandating rationalizing the dictated purity level of the captured CO2 and valorizing the projects. However, such thrifty initiatives to moderate the costs of the selected CO2 removal technologies can lead to underlying cascading effects of the lower purity recovered CO2 on systems design and its operation.\u0000 As part of the nation's strategic objective to reduce carbon footprint, CO2 has been recovered for EOR re-injection applications. Relaxing the purity specification met by the CO2 capture units can positively improve the cost of the recovery plant while may potentially have adverse impacts on CO2 pipeline integrity.\u0000 This paper provides a comprehensive analysis of the impact of the CO2 purity specification on the flow assurance safety performance of dense phase CO2 pipeline. It is worth highlighting that the design of CO2 systems is challenged by the paucity of the available reference design guidelines since domain of CO2 itself is still evolving under an active area of research.\u0000 Although some previous publications have demonstrated the latent underlying effects of imputiries such as (N2, H2, SO2, NO2, CH4, C2H6, and Argon) on the physical and thermodynamic behavior of CO2 systems, however, this was supported by literature experimental modelling without transient analysis. In this paper, the behavior of varying CO2 purity levels on the design and operational aspects of CO2 pipeline is substantiated and both steady state and transient flow assurance modelling are presented. Gauging the system's design integrity cannot be solely assured from the perspective of steady state behavior and hence this paper's findings provide additional infor","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85031267","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. Gadelhak, Mohamed Al-Badi, Ahmed Al-Bairaq, E. Al Mheiri, Abdullah Haj Al-Hosani, Z. Ahmed, Sami Ullah Bashir Ahmed, Mubashir Ahmed, Waleed Omar Abedelkhalik, Sameh Hassan Naser, Haysam El-Shater, Wessam Al Assar, Steve Ross, Blair Duncan
The Increase of inactive wells due to subsurface integrity issue is observed in brown fields, Fig-1 is, showing the record for onshore UAE asset, the economic challenges is calling for alternative solutions to restore well integrity with lower cost. Straddle packer application is consists of two tandom packers with spacer pipe in between with anchoring system deployed riglessly in the well to isolate the communication point between Ann A and Tubing.Fig-2, Communication between tubing and annulus A (Failure of primary barrier) is identified as the right candidate wells for straddle packer application, First step is to clearly identify the point of communication, it has been done by annulus pressure investigation excersize during flowing and shut in condition, observing the return of annulus fluid which was the same produced gas Noise log has been conducted and clearly identified the communication point at SPM (Side Pocket Mandrel) to be used for emergency killing, Tubing integrity test was conducted using nippless plugs and inflow test below and above the leak point and confirm no other leak points within the tubing Engineering drawing for the leaking assembly was reviewed to design the dimension of straddle packer assembly, length and packer size It is recommended to deploy the assembly using electric line correlation for accurate depth selection After setting annulus pressure observed no build up Well opened safely to production Leak point arrested, well primary barrier restored Removed from DWS (drilling and workover schedule) and restore well production in addition to improving inactive string KPI for Gas asset Save almost work over cost for gas well XX-197 The way forward is to check the scalability of extending this application among other ADNOC assets and to screen the right candidate wells for this application To add this application as a part of well integrity procedures and recommendations for such like cases
{"title":"Lead Application to Cure Sap Wells by Deploying Straddle Packer, Success Story","authors":"A. Gadelhak, Mohamed Al-Badi, Ahmed Al-Bairaq, E. Al Mheiri, Abdullah Haj Al-Hosani, Z. Ahmed, Sami Ullah Bashir Ahmed, Mubashir Ahmed, Waleed Omar Abedelkhalik, Sameh Hassan Naser, Haysam El-Shater, Wessam Al Assar, Steve Ross, Blair Duncan","doi":"10.2118/207840-ms","DOIUrl":"https://doi.org/10.2118/207840-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The Increase of inactive wells due to subsurface integrity issue is observed in brown fields, Fig-1 is, showing the record for onshore UAE asset, the economic challenges is calling for alternative solutions to restore well integrity with lower cost.\u0000 Straddle packer application is consists of two tandom packers with spacer pipe in between with anchoring system deployed riglessly in the well to isolate the communication point between Ann A and Tubing.Fig-2,\u0000 \u0000 \u0000 \u0000 Communication between tubing and annulus A (Failure of primary barrier) is identified as the right candidate wells for straddle packer application,\u0000 First step is to clearly identify the point of communication, it has been done by annulus pressure investigation excersize during flowing and shut in condition, observing the return of annulus fluid which was the same produced gas\u0000 Noise log has been conducted and clearly identified the communication point at SPM (Side Pocket Mandrel) to be used for emergency killing,\u0000 Tubing integrity test was conducted using nippless plugs and inflow test below and above the leak point and confirm no other leak points within the tubing\u0000 Engineering drawing for the leaking assembly was reviewed to design the dimension of straddle packer assembly, length and packer size\u0000 It is recommended to deploy the assembly using electric line correlation for accurate depth selection\u0000 After setting annulus pressure observed no build up\u0000 Well opened safely to production\u0000 \u0000 \u0000 \u0000 Leak point arrested, well primary barrier restored\u0000 Removed from DWS (drilling and workover schedule) and restore well production in addition to improving inactive string KPI for Gas asset\u0000 Save almost work over cost for gas well XX-197\u0000 \u0000 \u0000 \u0000 The way forward is to check the scalability of extending this application among other ADNOC assets and to screen the right candidate wells for this application\u0000 To add this application as a part of well integrity procedures and recommendations for such like cases\u0000","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84969654","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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