Darhim M. Noureldien, Samy Kamal, K. Hemdan, H. Abdallah, A. Hassan
The lifecycle of any field consists of three main periods; green, plateau and maturity periods. Currently most of GUPCO fields are brown what made us very concerned to sustain and even increase our production. To achieve that, we have looked at new different options to exploit our resources better. Generally, this can be achieved by whether optimizing current system, applying new technology or evaluating unconventional resources. One of the high-potential resources that we do have in GUPCO is unconventional resources with many tight carbonate formations. Nevertheless, we did not try to appraise it before since most of our reservoirs are clastics that can be easily characterized and evaluated. On the other hand, tight carbonate formations cannot be characterized or appraised utilizing conventional logging tools or even classical reservoir engineering concepts. It always requires unique techniques relevant to its unique complexity degree especially in presence of micro-porosity and unknown fluid content. This paper sheds light on Appraisal Unconventional Resource Study that resulted in the first successful producer in the company. GUPCO started to appraise tight carbonate rocks (named Thebes in Lower Eocene) and basaltic intrusion in GoS. This study involved high integration between key disciplines; Petrophysics, Petrology and Reservoir Engineering. To manage uncertainty, we have acquired wide range of data types starting from advanced petrophysical logging tools like Magnetic Resonance, Borehole Imaging and spectroscopy, and full petro-graphic description, reaching to predicting reservoir dynamic performance using measured pressure points (RFT), its analysis and fluid characterization. Ultimately, we have succeeded to completely characterize Thebes formation, and proposing its development plan. The first successful well resulted in 300 BOPD gain as the first successful tight carbonate producer in GUPCO. Development plan is being built to drill new wells targeting unconventional resources including a few possible potential in basalt intrusions, as well. Dealing with unconventional resources is not an easy task. It requires a lot of work and analysis. Having all of your homework done is not always enough, you have to integrate with interrelated disciplines to link dots and complete the picture. In this paper, we have conceived a new approach in evaluating such formations, and it is a very good example of managing uncertainty by integrating different data to convert hypothesis into reality that can be translated ultimately into oil production and revenues.
{"title":"Unlocking Unconventional Resources in GUPCO: Case Study from Egypt","authors":"Darhim M. Noureldien, Samy Kamal, K. Hemdan, H. Abdallah, A. Hassan","doi":"10.2118/197609-ms","DOIUrl":"https://doi.org/10.2118/197609-ms","url":null,"abstract":"\u0000 The lifecycle of any field consists of three main periods; green, plateau and maturity periods. Currently most of GUPCO fields are brown what made us very concerned to sustain and even increase our production. To achieve that, we have looked at new different options to exploit our resources better. Generally, this can be achieved by whether optimizing current system, applying new technology or evaluating unconventional resources.\u0000 One of the high-potential resources that we do have in GUPCO is unconventional resources with many tight carbonate formations. Nevertheless, we did not try to appraise it before since most of our reservoirs are clastics that can be easily characterized and evaluated. On the other hand, tight carbonate formations cannot be characterized or appraised utilizing conventional logging tools or even classical reservoir engineering concepts. It always requires unique techniques relevant to its unique complexity degree especially in presence of micro-porosity and unknown fluid content. This paper sheds light on Appraisal Unconventional Resource Study that resulted in the first successful producer in the company.\u0000 GUPCO started to appraise tight carbonate rocks (named Thebes in Lower Eocene) and basaltic intrusion in GoS. This study involved high integration between key disciplines; Petrophysics, Petrology and Reservoir Engineering. To manage uncertainty, we have acquired wide range of data types starting from advanced petrophysical logging tools like Magnetic Resonance, Borehole Imaging and spectroscopy, and full petro-graphic description, reaching to predicting reservoir dynamic performance using measured pressure points (RFT), its analysis and fluid characterization. Ultimately, we have succeeded to completely characterize Thebes formation, and proposing its development plan. The first successful well resulted in 300 BOPD gain as the first successful tight carbonate producer in GUPCO. Development plan is being built to drill new wells targeting unconventional resources including a few possible potential in basalt intrusions, as well.\u0000 Dealing with unconventional resources is not an easy task. It requires a lot of work and analysis. Having all of your homework done is not always enough, you have to integrate with interrelated disciplines to link dots and complete the picture. In this paper, we have conceived a new approach in evaluating such formations, and it is a very good example of managing uncertainty by integrating different data to convert hypothesis into reality that can be translated ultimately into oil production and revenues.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89994564","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. T. Al-Hameedi, H. Alkinani, S. Dunn-Norman, M. A. Al-Alwani, Justin D. Feliz, A. Alshammari, H. Albazzaz, Z. Hamoud, R. A. Mutar, W. Al-Bazzaz
The use of conventional chemical additives to control drilling mud specifications causes serious health, safety, and environmental side effects. To mitigate these lasting hazards, an economic multifunctional bioenhancers should be exploited as additives in place of the traditional materials to achieve the desired drilling mud properties. Using a bioenhancer is not only safer for the environment, but it poses no risk to drilling personnel and is more cost-efficient than conventional methods. In this work, two concentrations of is Palm Tree Leave Powder (PTLP) were added to the base mud and drilling fluid properties were measured. The pH test demonstrated PTLP's ability to minimize alkalinity. At 1.5% (11 gm) PTLP, the pH was decreased by 21%, while 3% (22 gm) PTLP showed a reduction of 28%. A reduction in seepage loss (cc/30min) of 26% and 32% was also observed, respectively, when comparing it to the reference fluid. Simultaneous improvement of the mud cake was seen over the reference fluid, signifying PTLP could also substitute fluid loss control agents. The plastic viscosity (PV) of the reference fluid was insignificantly affected by the introduction 1.5% (11gm) PTLP. However, when the concentration of PTLP was increased to 3% (22 gm) a tangible increase in PV was seen due to the inefficient grinding of the palm tree leaves (PTL) and irregular dispersal of particle sizes. To mitigate this, a more effective form of grinding for PTL is needed as well as a sieve analysis to ensure equal distribution of particle sizes. The second component of viscosity, yield point (YP), was drastically reduced by 59% at both 1.5% (11 gm) and 3% (22 gm) as compared to the reference fluid. Additionally, initial and final gel strengths were significantly reduced at both concentrations. These results are an indicator that PTLP can be a viable option as a thinning material for water-based mud. Considering the previously stated results, PTLP can be a feasible replacement or at least supportive material for conventional pH reducers, filtration loss control agents, and viscosity thinners. This biodegradable drilling mud additive shows great potential and is a practical option to replace or at least support toxic chemicals traditionally used such as lignosulphonate, chrome-lignite, and Resinex. This work outlines a practical guide for reducing drilling fluid costs as well as the impact on drilling personnel and the environment.
{"title":"Laboratory Study of Environmentally Friendly Drilling Fluid Additives to be used a Thinner in Water-Based Muds","authors":"A. T. Al-Hameedi, H. Alkinani, S. Dunn-Norman, M. A. Al-Alwani, Justin D. Feliz, A. Alshammari, H. Albazzaz, Z. Hamoud, R. A. Mutar, W. Al-Bazzaz","doi":"10.2118/197846-ms","DOIUrl":"https://doi.org/10.2118/197846-ms","url":null,"abstract":"The use of conventional chemical additives to control drilling mud specifications causes serious health, safety, and environmental side effects. To mitigate these lasting hazards, an economic multifunctional bioenhancers should be exploited as additives in place of the traditional materials to achieve the desired drilling mud properties. Using a bioenhancer is not only safer for the environment, but it poses no risk to drilling personnel and is more cost-efficient than conventional methods.\u0000 In this work, two concentrations of is Palm Tree Leave Powder (PTLP) were added to the base mud and drilling fluid properties were measured. The pH test demonstrated PTLP's ability to minimize alkalinity. At 1.5% (11 gm) PTLP, the pH was decreased by 21%, while 3% (22 gm) PTLP showed a reduction of 28%. A reduction in seepage loss (cc/30min) of 26% and 32% was also observed, respectively, when comparing it to the reference fluid. Simultaneous improvement of the mud cake was seen over the reference fluid, signifying PTLP could also substitute fluid loss control agents. The plastic viscosity (PV) of the reference fluid was insignificantly affected by the introduction 1.5% (11gm) PTLP. However, when the concentration of PTLP was increased to 3% (22 gm) a tangible increase in PV was seen due to the inefficient grinding of the palm tree leaves (PTL) and irregular dispersal of particle sizes. To mitigate this, a more effective form of grinding for PTL is needed as well as a sieve analysis to ensure equal distribution of particle sizes. The second component of viscosity, yield point (YP), was drastically reduced by 59% at both 1.5% (11 gm) and 3% (22 gm) as compared to the reference fluid. Additionally, initial and final gel strengths were significantly reduced at both concentrations. These results are an indicator that PTLP can be a viable option as a thinning material for water-based mud.\u0000 Considering the previously stated results, PTLP can be a feasible replacement or at least supportive material for conventional pH reducers, filtration loss control agents, and viscosity thinners. This biodegradable drilling mud additive shows great potential and is a practical option to replace or at least support toxic chemicals traditionally used such as lignosulphonate, chrome-lignite, and Resinex. This work outlines a practical guide for reducing drilling fluid costs as well as the impact on drilling personnel and the environment.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"2016 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87874633","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}
Chenji Wei, Yuhe Wang, Baozhu Li, Jingjian Zhang, Wang Zhang, J. Wu
Miscible gas displacement is a promising enhanced oil recovery method in carbonate reservoirs technologically and economically. Though miscibility can be well understood using core-scale experimental and numerical models, the miscible displacement process in complex heterogeneous and multi-dimensional carbonate reservoirs is more complicated and needs further analysis. In this paper, we present our effort in probing the miscible gas displacement characteristics in a carbonate reservoir with baffles based on data from a real field. Using compositional modeling, we evaluate miscible gas injection process in heterogeneous carbonate reservoir with baffles. Together with the detailed miscible front development in specific parts of the reservoir, the analysis also takes advantage of gravity stabilization realized by implementing the corresponding injector-producer pattern. This paper presents an analysis of miscible gas displacement process, which can be considered as an extension from a simple one-dimensional model to more complex heterogeneous and multi-dimensional system. Using data from a real carbonate reservoir with baffles, we analyze the CO2 injection for the drive processes. The analysis is combined with the consideration of the effects of baffles and wettability. Mainly due to the multi-dimensional flow, our results show that the minimum miscibility pressure is higher than one-dimensional system. Besides, our results indicate gravity stabilization could be well maintained by proper injector-producer pattern. We also report the sensitivity analysis for wettability changes in carbonates. This paper offers a study to analyze and evaluate miscible gas flooding process in heterogeneous carbonate reservoirs. Using a real case data, the study can help reservoir engineers to better design miscible gas flooding for other similar situations.
{"title":"Miscible Gas Injection in Heterogeneous Carbonate Reservoirs with Extensive Baffles","authors":"Chenji Wei, Yuhe Wang, Baozhu Li, Jingjian Zhang, Wang Zhang, J. Wu","doi":"10.2118/197345-ms","DOIUrl":"https://doi.org/10.2118/197345-ms","url":null,"abstract":"\u0000 Miscible gas displacement is a promising enhanced oil recovery method in carbonate reservoirs technologically and economically. Though miscibility can be well understood using core-scale experimental and numerical models, the miscible displacement process in complex heterogeneous and multi-dimensional carbonate reservoirs is more complicated and needs further analysis. In this paper, we present our effort in probing the miscible gas displacement characteristics in a carbonate reservoir with baffles based on data from a real field.\u0000 Using compositional modeling, we evaluate miscible gas injection process in heterogeneous carbonate reservoir with baffles. Together with the detailed miscible front development in specific parts of the reservoir, the analysis also takes advantage of gravity stabilization realized by implementing the corresponding injector-producer pattern.\u0000 This paper presents an analysis of miscible gas displacement process, which can be considered as an extension from a simple one-dimensional model to more complex heterogeneous and multi-dimensional system. Using data from a real carbonate reservoir with baffles, we analyze the CO2 injection for the drive processes. The analysis is combined with the consideration of the effects of baffles and wettability. Mainly due to the multi-dimensional flow, our results show that the minimum miscibility pressure is higher than one-dimensional system. Besides, our results indicate gravity stabilization could be well maintained by proper injector-producer pattern. We also report the sensitivity analysis for wettability changes in carbonates.\u0000 This paper offers a study to analyze and evaluate miscible gas flooding process in heterogeneous carbonate reservoirs. Using a real case data, the study can help reservoir engineers to better design miscible gas flooding for other similar situations.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91151738","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}
Riaz Khan, Ahmed Al Hanaee, Kate Al Tameemi, Redy Kurniawan, Neil Omonigho, A. Gueddoud, A. Abdelaal, A. Vantala
The Gachsaran Formation across Onshore Abu Dhabi and possibly across U.A.E poses high potential of generating Shallow Biogenic Gas (mainly methane) and as such has taken the attention to further investigate, understand and evaluate its capability for promising Gas Resources. The paper provides a detailed G&G analysis that has potentially allowed an appropriate characterization of this unique formation that has first time uncovered interesting data responses in differentiating the sweet spot. For the first time in the history of U.A.E., new data was acquired targeting specifically the Miocene, Gachsaran Formation. This includes; 2D Seismic and party 3D Seismic interpretations, thousands of feet continuous core, conventional and advanced subsurface and surface loggings, Formation Pressure, Fluid sampling, Geochemical and Geomechanical labs measurements, stimulations and Frac tests data. The Gachsaran Formation is very challenging due to complex, thinly bedded and intercalated lithological varitions, and tightness provides difficulties in identifying the promising areas of Gas bearing layers. A comprehensive analysis was performed, in the light of regional understanding, by integrating the results of all available data in the form of correlation, cluster analysis, cross plotting and well based rock physics to differentiate the effect of Gas existence within the formation. The potential zones were further tested and results were integrated to confirm the analysis. The Gachsaran Formation has been subdivided into Lower, Middle and Upper Gachsaran Members. The Lower Member is predominantly evaporitic, becoming more argillaceous carbonate and shale –bearing in the the Middle Member with comparatively less anhydrites. The Upper Member contains mainly anhydrites with interbedded shales and carbonates. The potential sequences which represent high Total Organic Carbon and Gas Shows are found within the Middle Gachsaran. Consequently, the Middle Gachsaran Member was analyzed based on the robust data acquisition performed. Several relationships among GR, TOC, Gas shows, Lithology, RHOB, NPHI, Sonic, AI, Vp/Vs, Gradient Impedance and XRD Clay mineralogy have been attempted to check possible identification of Gas existence effect on the data. This has led to identify the sweet spots caused by the existence of any dominant Gas within the Study Area. The potential zones were confirmed by well testing. Furthermore, data variables were distributed within a 3D Grid and based on the analysis performed the area of sweet spots were identified. In the next phase of the study, the results will be integrated with the upcoming Geophysical Seismic Inversion studies to further optimize the possibility of identifying the sweet spot across the Study Area. The robust data acquisition targeting Gachsaran was performed first time in the history of U.A.E. The results are encouraging in establishing the relationship to identify the dominant existence of Gas effects within the
{"title":"Characterization of Unique Miocene Gachsaran Formation in Relation to Prospective Shallow Biogenic Gas Resources Across Onshore Abu Dhabi, United Arab Emirates","authors":"Riaz Khan, Ahmed Al Hanaee, Kate Al Tameemi, Redy Kurniawan, Neil Omonigho, A. Gueddoud, A. Abdelaal, A. Vantala","doi":"10.2118/197195-ms","DOIUrl":"https://doi.org/10.2118/197195-ms","url":null,"abstract":"\u0000 The Gachsaran Formation across Onshore Abu Dhabi and possibly across U.A.E poses high potential of generating Shallow Biogenic Gas (mainly methane) and as such has taken the attention to further investigate, understand and evaluate its capability for promising Gas Resources. The paper provides a detailed G&G analysis that has potentially allowed an appropriate characterization of this unique formation that has first time uncovered interesting data responses in differentiating the sweet spot.\u0000 For the first time in the history of U.A.E., new data was acquired targeting specifically the Miocene, Gachsaran Formation. This includes; 2D Seismic and party 3D Seismic interpretations, thousands of feet continuous core, conventional and advanced subsurface and surface loggings, Formation Pressure, Fluid sampling, Geochemical and Geomechanical labs measurements, stimulations and Frac tests data. The Gachsaran Formation is very challenging due to complex, thinly bedded and intercalated lithological varitions, and tightness provides difficulties in identifying the promising areas of Gas bearing layers. A comprehensive analysis was performed, in the light of regional understanding, by integrating the results of all available data in the form of correlation, cluster analysis, cross plotting and well based rock physics to differentiate the effect of Gas existence within the formation. The potential zones were further tested and results were integrated to confirm the analysis.\u0000 The Gachsaran Formation has been subdivided into Lower, Middle and Upper Gachsaran Members. The Lower Member is predominantly evaporitic, becoming more argillaceous carbonate and shale –bearing in the the Middle Member with comparatively less anhydrites. The Upper Member contains mainly anhydrites with interbedded shales and carbonates. The potential sequences which represent high Total Organic Carbon and Gas Shows are found within the Middle Gachsaran.\u0000 Consequently, the Middle Gachsaran Member was analyzed based on the robust data acquisition performed. Several relationships among GR, TOC, Gas shows, Lithology, RHOB, NPHI, Sonic, AI, Vp/Vs, Gradient Impedance and XRD Clay mineralogy have been attempted to check possible identification of Gas existence effect on the data. This has led to identify the sweet spots caused by the existence of any dominant Gas within the Study Area. The potential zones were confirmed by well testing. Furthermore, data variables were distributed within a 3D Grid and based on the analysis performed the area of sweet spots were identified. In the next phase of the study, the results will be integrated with the upcoming Geophysical Seismic Inversion studies to further optimize the possibility of identifying the sweet spot across the Study Area.\u0000 The robust data acquisition targeting Gachsaran was performed first time in the history of U.A.E. The results are encouraging in establishing the relationship to identify the dominant existence of Gas effects within the","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87562479","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}
Pipelines are the most economically viable mode of transportation for oil and gas. Every pipeline is monitored 24×7 using meters distributed across the pipeline. Flow, temperature and pressure meters are the most common and essential for continuous and efficient operation of pipelines. Like any other instrument these meters also have uncertainty and prone to error due to irregular calibration, drift, gross error and other such events. The overall accuracy of pipeline metering increases as the distance between consecutive meters decreases. It is also affected by the placement of meters at critical locations like pipeline tapouts, tapins and consumers points. Economics do not allow pipeline operators to install beyond a certain amount of metering assets. The complexity to efficiently calculate the product in and out of a gas pipeline is more compared to a liquid pipeline. It arises due to the high compressibility of gases compared to liquids. Gas pipelines operate at much higher pressure than oil pipelines. The trapped gas inside a gas pipeline can be called line pack of that pipeline. The line pack is very sensitive to two natural factors pressure and temperature of the pipeline. Oil pipelines carry one fluid at a time. Gas pipelines on the other hand carry several gases as a mixture. Unlike oil, gas billings are calculated as the energy the gas mixture carries to the consumer. Due to the mixture, gas composition is another essential factor to accurately calculate energy of the mixture. This paper discusses the challenges of calculating various transport factors and phenomena in gas pipelines and how methods like gross error correction and machine learning can be used to increase the accuracy. The results and conclusions are derived from the applications of these methods to natural gas transportation pipeline. Some of most important conclusions obtained were Understanding the pattern of on-field meter data with ideal meter provides insights in the root cause of the problem. e.g. sudden spike in temperature leading to error in line pack.Creating digital twin of all metering assets allows faster isolation of pipeline sections having calculation errors. e.g. by monitoring the difference between field and ideal parameters.Having a central meter diagnostics system that combines the data from meters of different make and models improve the pattern recognition and error detection ability.Gross error detection isolates the meters inducing error. The feedback can be provided to the machine learning algorithms for root cause analysis. Note: This paper only covers the gross error of meters. There are methods used to reduce other meter errors namely random, limiting and systematic not covered in this paper. Readers are requested to read relevant material to understand the complete scope of errors in metering systems.
{"title":"Gas Reconciliation with Advance Error Reduction","authors":"Varun Nidhi, Rakesh Rao, Prakash Chhapolia","doi":"10.2118/197689-ms","DOIUrl":"https://doi.org/10.2118/197689-ms","url":null,"abstract":"\u0000 Pipelines are the most economically viable mode of transportation for oil and gas. Every pipeline is monitored 24×7 using meters distributed across the pipeline. Flow, temperature and pressure meters are the most common and essential for continuous and efficient operation of pipelines. Like any other instrument these meters also have uncertainty and prone to error due to irregular calibration, drift, gross error and other such events. The overall accuracy of pipeline metering increases as the distance between consecutive meters decreases. It is also affected by the placement of meters at critical locations like pipeline tapouts, tapins and consumers points. Economics do not allow pipeline operators to install beyond a certain amount of metering assets.\u0000 The complexity to efficiently calculate the product in and out of a gas pipeline is more compared to a liquid pipeline. It arises due to the high compressibility of gases compared to liquids. Gas pipelines operate at much higher pressure than oil pipelines. The trapped gas inside a gas pipeline can be called line pack of that pipeline. The line pack is very sensitive to two natural factors pressure and temperature of the pipeline. Oil pipelines carry one fluid at a time. Gas pipelines on the other hand carry several gases as a mixture. Unlike oil, gas billings are calculated as the energy the gas mixture carries to the consumer. Due to the mixture, gas composition is another essential factor to accurately calculate energy of the mixture.\u0000 This paper discusses the challenges of calculating various transport factors and phenomena in gas pipelines and how methods like gross error correction and machine learning can be used to increase the accuracy. The results and conclusions are derived from the applications of these methods to natural gas transportation pipeline. Some of most important conclusions obtained were Understanding the pattern of on-field meter data with ideal meter provides insights in the root cause of the problem. e.g. sudden spike in temperature leading to error in line pack.Creating digital twin of all metering assets allows faster isolation of pipeline sections having calculation errors. e.g. by monitoring the difference between field and ideal parameters.Having a central meter diagnostics system that combines the data from meters of different make and models improve the pattern recognition and error detection ability.Gross error detection isolates the meters inducing error. The feedback can be provided to the machine learning algorithms for root cause analysis.\u0000 Note: This paper only covers the gross error of meters. There are methods used to reduce other meter errors namely random, limiting and systematic not covered in this paper. Readers are requested to read relevant material to understand the complete scope of errors in metering systems.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86946547","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}
H. Yin, M. Nicholis, Ahmed Al Teneiji, N. Aboud, A. Salem
Resistivity is one of the most important log that is required in water saturation (Sw) calculation, reservoir characterization, field assessment and hydrocarbon production. However, borehole environmental and borehole-to-bedding geometric effects on LWD propagation resistivity logs are inevitable. For instance, severe "polarization horn" responses from LWD propagation resistivity logs are commonly encounted in High-Angle & Horizontal (HAHZ) wells near bed boundaries with high resistivity contrast. These "polarization horns" in LWD propagation resistivity responses in HAHZ wells are not accurate resistivity profile, and consequently, impacts Sw calculation. In this paper, an innovative LWD propagation resistivity Tool-Response-Modeling (TRM) workflow has been developed and applied to six typical Maximum Reservoir Contact (MRC) wells drilled in a giant carbonate field in Middle East. The inverted resistivity profiles along the well path result in more accurate resistivity and, hence, more accurate Sw calculations (as compared to capillary pressure- and core-based Sw calculations). Additionally, TRM results yield new insights on to both maintain the well in the target formation and reduce these "polarization horn" responses during geosteering operations. The case studies demonstrated that TRM and this workflow has an important and critical roles in accurate Sw calculation, formation evaluation and field assessment, and hydrocarbon production.
{"title":"LWD Resistivity Tool Response Modeling in High Angle and Horizontal Maximum Reservoir Contact Wells and its Significant Impact on Water Saturation Calculation: Case Study in a Giant Carbonate Field in Middle East","authors":"H. Yin, M. Nicholis, Ahmed Al Teneiji, N. Aboud, A. Salem","doi":"10.2118/197896-ms","DOIUrl":"https://doi.org/10.2118/197896-ms","url":null,"abstract":"\u0000 Resistivity is one of the most important log that is required in water saturation (Sw) calculation, reservoir characterization, field assessment and hydrocarbon production. However, borehole environmental and borehole-to-bedding geometric effects on LWD propagation resistivity logs are inevitable. For instance, severe \"polarization horn\" responses from LWD propagation resistivity logs are commonly encounted in High-Angle & Horizontal (HAHZ) wells near bed boundaries with high resistivity contrast. These \"polarization horns\" in LWD propagation resistivity responses in HAHZ wells are not accurate resistivity profile, and consequently, impacts Sw calculation.\u0000 In this paper, an innovative LWD propagation resistivity Tool-Response-Modeling (TRM) workflow has been developed and applied to six typical Maximum Reservoir Contact (MRC) wells drilled in a giant carbonate field in Middle East. The inverted resistivity profiles along the well path result in more accurate resistivity and, hence, more accurate Sw calculations (as compared to capillary pressure- and core-based Sw calculations). Additionally, TRM results yield new insights on to both maintain the well in the target formation and reduce these \"polarization horn\" responses during geosteering operations. The case studies demonstrated that TRM and this workflow has an important and critical roles in accurate Sw calculation, formation evaluation and field assessment, and hydrocarbon production.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85689880","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 Barik, Miqrat and Amin formations are deep, tight reservoirs of the Haima Supergroup that provide the majority of gas production in the Sultanate of Oman. The Miqrat formation is a feldspathic sand/shale sequence with complex pore structure and occasional bitumen presence. In the area of interest, it occurs at a depth of approximately 5000 m. Average porosity varies from 5 to 9%, average permeability for Lower Miqrat does not exceed 0.1 mD. In general, Archie equation derived saturation in low porosity rocks is subject to medium to high uncertainty. Therefore the most common challenge in the petrophysical evaluation of tight reservoirs is the determination of gas saturation and fluid type identification. In an effort to improve the reliability of saturation calculation and fluid typing, several different methods were tested including cased-hole Pulsed Neutron Logs (PNL). The classical sigma interpretation was found to be too sensitive to input parameters and did not provide significant improvement to saturation determination in the complex Haima lithologies. An important breakthrough was made when the dynamics of the mud filtrate invasion process in these reservoirs was understood. During open-hole logging usually very little or no gas effect is observed on logs with negligible or no density-neutron separation. The reason is considered to be deep mud filtrate invasion pushing moveable gas beyond the depth of investigation of radioactive logs. One or two months later, the filtrate in the invasion zone dissipates with gas returning to the near wellbore formation. The best match between log calculated moveable gas saturation and production test data was obtained using a reverse time-lapse technique, with PNL cased-hole logs compared to baseline open-hole neutron measurements. The changes in neutron porosity with time can be attributed to moveable gas saturation. Careful neutron log quality control and normalization across non-reservoir and known water-bearing sections is required. Knowing the hydrogen index of gas, we can calculate the moveable gas saturation from the difference in neutron log response. In contrast to the sigma approach, an accurate rock matrix model is not required. This paper describes the Reverse Time-Lapse technique: a novel application of the classic time-lapse technique between open-hole neutron and cased-hole PNL. The case studies demonstrate that this technique is applicable for completion decision making and field-scale development planning.
{"title":"Reverse Time-Lapse Technique for Moveable Gas Identification","authors":"R. Lukmanov, Amani Kindi","doi":"10.2118/197455-ms","DOIUrl":"https://doi.org/10.2118/197455-ms","url":null,"abstract":"\u0000 The Barik, Miqrat and Amin formations are deep, tight reservoirs of the Haima Supergroup that provide the majority of gas production in the Sultanate of Oman. The Miqrat formation is a feldspathic sand/shale sequence with complex pore structure and occasional bitumen presence. In the area of interest, it occurs at a depth of approximately 5000 m. Average porosity varies from 5 to 9%, average permeability for Lower Miqrat does not exceed 0.1 mD. In general, Archie equation derived saturation in low porosity rocks is subject to medium to high uncertainty. Therefore the most common challenge in the petrophysical evaluation of tight reservoirs is the determination of gas saturation and fluid type identification.\u0000 In an effort to improve the reliability of saturation calculation and fluid typing, several different methods were tested including cased-hole Pulsed Neutron Logs (PNL). The classical sigma interpretation was found to be too sensitive to input parameters and did not provide significant improvement to saturation determination in the complex Haima lithologies. An important breakthrough was made when the dynamics of the mud filtrate invasion process in these reservoirs was understood. During open-hole logging usually very little or no gas effect is observed on logs with negligible or no density-neutron separation. The reason is considered to be deep mud filtrate invasion pushing moveable gas beyond the depth of investigation of radioactive logs. One or two months later, the filtrate in the invasion zone dissipates with gas returning to the near wellbore formation.\u0000 The best match between log calculated moveable gas saturation and production test data was obtained using a reverse time-lapse technique, with PNL cased-hole logs compared to baseline open-hole neutron measurements. The changes in neutron porosity with time can be attributed to moveable gas saturation. Careful neutron log quality control and normalization across non-reservoir and known water-bearing sections is required. Knowing the hydrogen index of gas, we can calculate the moveable gas saturation from the difference in neutron log response. In contrast to the sigma approach, an accurate rock matrix model is not required.\u0000 This paper describes the Reverse Time-Lapse technique: a novel application of the classic time-lapse technique between open-hole neutron and cased-hole PNL. The case studies demonstrate that this technique is applicable for completion decision making and field-scale development planning.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79739285","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}
Ryosuke Kidogawa, N. Yoshida, K. Fuse, Yuta Morimoto, K. Takatsu, Keisuke Yamamura
Productivity of multistage-fractured gas wells is possibly degraded by conductivity impairments and non-Darcy flow during long-term production. Such degradations are pronounced by flow convergence to short perforated intervals, while it is challenging to identify degraded stages for remediation. Moreover, remedial actions can be expensive under high-pressure and high-temperature (HP/HT) environment. A field case demonstrates successful application of re-perforation as a cost-effective way to mitigate the flow convergence by prioritizing targets with multi-rate production logging (PL) results. This work presents theoretical investigations using numerical simulations and field execution of re-perforation for a well with six-stage fracturing treatments in a HP/HT volcanic gas reservoir onshore Japan. Apparent conductivity reduction was suspected during more than 15 years of production, and it was pronounced by non-Darcy flow effects associated with flow convergence to short perforated intervals. Multi-rate PL was employed to identify impaired stages by quantifying inflow performance relationship (IPR) of each stage under transient flow-after-flow testing. The impaired stages were re-perforated adding perforation intervals with wireline-conveyed perforators. Pre/post pressure build-up tests and post-job PL were used to validate productivity improvements. Target zones for re-perforations were identified and prioritized with results of the multi-rate PL conducted. The stage IPRs were drawn, and relatively large non-Darcy effects were identified in three stages by shapes of the IPRs and/or decreasing inflow contributions as surface rate increased. Also, temperature log showed steep temperature change at bottom of the 4th stage; the fracture might propagate below the perforated interval. Ranges of production increment were estimated using a numerical model calibrated against the estimated stage IPRs. The estimated increment was in range of 15% to 30% with planned re-perforation program while its magnitude depended on connection between new perforations and existing fractures. Afterwards, re-perforation job was done, and, the gas rate was confirmed to be increased by 26% with the same well-head pressure after one month of production. The post-job PL was conducted three months after the re-perforation. The well's IPR was improved implying reduction of the non-Darcy effects. Results of pressure build-up tests also indicated reduction of skin factor. The stage IPRs were redrawn with the post-job PL, and they suggested clear improvements in two stages where screen-out occurred during fracturing treatments and a stage where significant non-Darcy effect was suspected. The workflow and strategy in this paper can be applied for productivity restoration in a cost-effective way to multi-stage fractured gas wells with short perforated intervals and impaired apparent conductivity during long-term production. Especially, the interpreted results suggested effectiv
{"title":"Productivity Improvement by Re-perforation of Multistage-fractured Wells in HP/HT Tight Gas Reservoirs: A Case History","authors":"Ryosuke Kidogawa, N. Yoshida, K. Fuse, Yuta Morimoto, K. Takatsu, Keisuke Yamamura","doi":"10.2118/197590-ms","DOIUrl":"https://doi.org/10.2118/197590-ms","url":null,"abstract":"\u0000 Productivity of multistage-fractured gas wells is possibly degraded by conductivity impairments and non-Darcy flow during long-term production. Such degradations are pronounced by flow convergence to short perforated intervals, while it is challenging to identify degraded stages for remediation. Moreover, remedial actions can be expensive under high-pressure and high-temperature (HP/HT) environment. A field case demonstrates successful application of re-perforation as a cost-effective way to mitigate the flow convergence by prioritizing targets with multi-rate production logging (PL) results.\u0000 This work presents theoretical investigations using numerical simulations and field execution of re-perforation for a well with six-stage fracturing treatments in a HP/HT volcanic gas reservoir onshore Japan. Apparent conductivity reduction was suspected during more than 15 years of production, and it was pronounced by non-Darcy flow effects associated with flow convergence to short perforated intervals. Multi-rate PL was employed to identify impaired stages by quantifying inflow performance relationship (IPR) of each stage under transient flow-after-flow testing. The impaired stages were re-perforated adding perforation intervals with wireline-conveyed perforators. Pre/post pressure build-up tests and post-job PL were used to validate productivity improvements.\u0000 Target zones for re-perforations were identified and prioritized with results of the multi-rate PL conducted. The stage IPRs were drawn, and relatively large non-Darcy effects were identified in three stages by shapes of the IPRs and/or decreasing inflow contributions as surface rate increased. Also, temperature log showed steep temperature change at bottom of the 4th stage; the fracture might propagate below the perforated interval. Ranges of production increment were estimated using a numerical model calibrated against the estimated stage IPRs. The estimated increment was in range of 15% to 30% with planned re-perforation program while its magnitude depended on connection between new perforations and existing fractures. Afterwards, re-perforation job was done, and, the gas rate was confirmed to be increased by 26% with the same well-head pressure after one month of production. The post-job PL was conducted three months after the re-perforation. The well's IPR was improved implying reduction of the non-Darcy effects. Results of pressure build-up tests also indicated reduction of skin factor. The stage IPRs were redrawn with the post-job PL, and they suggested clear improvements in two stages where screen-out occurred during fracturing treatments and a stage where significant non-Darcy effect was suspected.\u0000 The workflow and strategy in this paper can be applied for productivity restoration in a cost-effective way to multi-stage fractured gas wells with short perforated intervals and impaired apparent conductivity during long-term production. Especially, the interpreted results suggested effectiv","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83842443","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}
Bilal Iftikhar Choudhry, M. Shaver, M. A. Alzaabi, T. Toki, S. Ali, I. Abdelkarim, Mario R. Oviedo Vargas, Javier Torres, Mohamed Ahmed Osman, Freddy Alfonso Mendez, Kresimir Vican, Chung Yee Lee
Over the course of drilling wells in one of ADNOC Offshore fields, there have been numerous endeavors in the Crestal region of the field with each well presenting its unique array of issues and challenges related to well construction, stability and delivery. Even while drilling two identical wells with extremely similar well designs and architecture, the wells encountered different and at times opposite responses from the formations being drilled. This resulted in the well construction becoming more problematic than expected in some cases while in others the situation was completely opposite, thus drilling and well construction went extremely smooth delivering the well ahead of time as opposed to the nearby sister well. While the denominators may be segregated based on commonality and differences, there is one particular aspect of the drilling process and planning that has been significantly overlooked, the Azimuth of the well particularly in the crestal region of the field. Over the years, investigation into the well trajectory, the well fluids and intrinsic properties have been dissected to arrive at a result but has not produced the expected success. The Azimuthal impact on the resultant seems to have been ignored to the extent of not understanding the Azimuth impact on a well trajectory. It is of paramount importance to investigate and identify the imp act since the related stresses and their directions directly define and drive the stability and the optimal mud weight needed to drill successful wells.
{"title":"Correlation of Wellbore Geometry with Geo-Mechanics and Drilling Practices in a Giant Offshore Field in Abu Dhabi","authors":"Bilal Iftikhar Choudhry, M. Shaver, M. A. Alzaabi, T. Toki, S. Ali, I. Abdelkarim, Mario R. Oviedo Vargas, Javier Torres, Mohamed Ahmed Osman, Freddy Alfonso Mendez, Kresimir Vican, Chung Yee Lee","doi":"10.2118/197216-ms","DOIUrl":"https://doi.org/10.2118/197216-ms","url":null,"abstract":"\u0000 Over the course of drilling wells in one of ADNOC Offshore fields, there have been numerous endeavors in the Crestal region of the field with each well presenting its unique array of issues and challenges related to well construction, stability and delivery. Even while drilling two identical wells with extremely similar well designs and architecture, the wells encountered different and at times opposite responses from the formations being drilled. This resulted in the well construction becoming more problematic than expected in some cases while in others the situation was completely opposite, thus drilling and well construction went extremely smooth delivering the well ahead of time as opposed to the nearby sister well.\u0000 While the denominators may be segregated based on commonality and differences, there is one particular aspect of the drilling process and planning that has been significantly overlooked, the Azimuth of the well particularly in the crestal region of the field. Over the years, investigation into the well trajectory, the well fluids and intrinsic properties have been dissected to arrive at a result but has not produced the expected success. The Azimuthal impact on the resultant seems to have been ignored to the extent of not understanding the Azimuth impact on a well trajectory. It is of paramount importance to investigate and identify the imp act since the related stresses and their directions directly define and drive the stability and the optimal mud weight needed to drill successful wells.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"12 50","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91508440","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}
Saikiran Kollamgunta, A. SrinivasaRaoG.V.R., H. Singh, F. Kamal, Oussama Takieddine
One of the major challenges in multi-phase pipelines is to manage slug during pigging to ensure safe and smooth operation of downstream facility. The liquid slug accumulated during pigging can result in process upset, shutdown if the downstream facilities are not designed to handle the anticipated slug volume. This paper discusses the benefits of by-pass pigging to efficiently handle the slug volume resulting in optimal use of assets and without compromising the field production. By-pass pigs are specially designed pigs with holes on the discs that allow part of the fluid to move from behind to the front of the pig. This design feature helps minimize the liquid slug accumulation in front of the pig and significantly reduces the slug volume as compared with conventional pigs. Dynamic Flow Simulator is used to analyze the performance of bypass pig. However, the use of bypass pigs involves careful assessment with respect to well fluids impurities such as presence of wax, solids or high asphaltenes which may block the holes and thus influence the operational efficiency. The liquid slugs generated during pigging operation can cause severe operational problems in terms of level and pressure fluctuations in a separator leading to poor separation, potential liquid flooding, increased flaring, emergency shutdown and production loss. In order to minimize the slugging impact, sufficient buffer volume is provided in the slug catcher/separator to accommodate the slugs generated in the pipeline during various operations. However, considering surge volume in existing separators, Brownfield Projects can impose risk due to space constraints. To mitigate the risk, production levels are normally reduced during pigging operations leads to production deferment. However, during revamp of existing facilities for higher production capacity or changed operating conditions where existing equipment sizes impose constraints, bypass pigging has been shown to provide useful and practical solutions. This option can also useful in providing reduced slug catcher sizes for "Greenfield Facilities" as well. Very importantly, the bypass pigging operation eliminates production loss with no facility upsets. The benefits of this technique are established through transient simulations, before being adopted in facility design and operation. This paper discusses the related case studies. This paper discusses the benefits of bypass pigging and the challenges to accommodate the increased surge volume in the existing slug catcher/separator system during pigging operation. The application of bypass pigging to limit slug volume is demonstrated using Dynamic Multiphase Flow Simulator and compares the results with conventional pigging operation. The proposed design solutions are based on NPCC's extensive and successful experience in tackling challenges in design of slug handling facilities especially in Brownfield projects.
{"title":"Innovative Solutions to Manage Slug Buildup in Multi-Phase Pipelines through Bypass Pigging","authors":"Saikiran Kollamgunta, A. SrinivasaRaoG.V.R., H. Singh, F. Kamal, Oussama Takieddine","doi":"10.2118/197205-ms","DOIUrl":"https://doi.org/10.2118/197205-ms","url":null,"abstract":"\u0000 One of the major challenges in multi-phase pipelines is to manage slug during pigging to ensure safe and smooth operation of downstream facility. The liquid slug accumulated during pigging can result in process upset, shutdown if the downstream facilities are not designed to handle the anticipated slug volume. This paper discusses the benefits of by-pass pigging to efficiently handle the slug volume resulting in optimal use of assets and without compromising the field production.\u0000 By-pass pigs are specially designed pigs with holes on the discs that allow part of the fluid to move from behind to the front of the pig. This design feature helps minimize the liquid slug accumulation in front of the pig and significantly reduces the slug volume as compared with conventional pigs. Dynamic Flow Simulator is used to analyze the performance of bypass pig. However, the use of bypass pigs involves careful assessment with respect to well fluids impurities such as presence of wax, solids or high asphaltenes which may block the holes and thus influence the operational efficiency.\u0000 The liquid slugs generated during pigging operation can cause severe operational problems in terms of level and pressure fluctuations in a separator leading to poor separation, potential liquid flooding, increased flaring, emergency shutdown and production loss. In order to minimize the slugging impact, sufficient buffer volume is provided in the slug catcher/separator to accommodate the slugs generated in the pipeline during various operations. However, considering surge volume in existing separators, Brownfield Projects can impose risk due to space constraints. To mitigate the risk, production levels are normally reduced during pigging operations leads to production deferment. However, during revamp of existing facilities for higher production capacity or changed operating conditions where existing equipment sizes impose constraints, bypass pigging has been shown to provide useful and practical solutions. This option can also useful in providing reduced slug catcher sizes for \"Greenfield Facilities\" as well. Very importantly, the bypass pigging operation eliminates production loss with no facility upsets. The benefits of this technique are established through transient simulations, before being adopted in facility design and operation. This paper discusses the related case studies.\u0000 This paper discusses the benefits of bypass pigging and the challenges to accommodate the increased surge volume in the existing slug catcher/separator system during pigging operation. The application of bypass pigging to limit slug volume is demonstrated using Dynamic Multiphase Flow Simulator and compares the results with conventional pigging operation. The proposed design solutions are based on NPCC's extensive and successful experience in tackling challenges in design of slug handling facilities especially in Brownfield projects.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76213054","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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