Estimating the lateral heterogeneity of geochemical properties of organic rich mudrocks is important for unconventional resource plays. Mature regions can rely on abundant well data to build empirical relationships and on traditional geostatistical methods to estimate properties between wells. However, well penetration in emerging plays are sparse and so these methods will not yield good results. In this case, quantitative seismic interpretation (QSI) might be helpful in estimating the desired properties. In this study, we use QSI based on a rock physics template in estimating the uncertainty of the geochemical properties of organic mudrocks of the Shublik Formation, North Slope, Alaska. A rock physics template incorporating lithology, pore fraction, kerogen fraction, and thermal maturity is constructed and validated using well data. The template clearly shows that the inversion problem is non-unique. Inverted impedances cubes are estimated from three seismic angle gathers (near with angles between 0° and 15°, mid with angle gathers between 15° and 30°, and far with angle gathers between 30° and 45°). The inversion is done using a model-based implementation with an initial earth model derived from the seismic velocity model used in the processing phase. By combining the rock physics template and the results of seismic inversion, multiple realizations of total organic content (TOC), matrix porosity, and brittleness index are generated. These parameters can be used for sweet spot detection. Lithological results can also be used as an input for basin and petroleum system modeling.
{"title":"Quantitative Seismic Interpretation Workflow for Sweet Spot Identification in Organic-Rich Mudrocks","authors":"M. A. Ibrahim, T. Mukerji, A. Scheirer","doi":"10.2118/197290-ms","DOIUrl":"https://doi.org/10.2118/197290-ms","url":null,"abstract":"\u0000 Estimating the lateral heterogeneity of geochemical properties of organic rich mudrocks is important for unconventional resource plays. Mature regions can rely on abundant well data to build empirical relationships and on traditional geostatistical methods to estimate properties between wells. However, well penetration in emerging plays are sparse and so these methods will not yield good results. In this case, quantitative seismic interpretation (QSI) might be helpful in estimating the desired properties. In this study, we use QSI based on a rock physics template in estimating the uncertainty of the geochemical properties of organic mudrocks of the Shublik Formation, North Slope, Alaska. A rock physics template incorporating lithology, pore fraction, kerogen fraction, and thermal maturity is constructed and validated using well data. The template clearly shows that the inversion problem is non-unique. Inverted impedances cubes are estimated from three seismic angle gathers (near with angles between 0° and 15°, mid with angle gathers between 15° and 30°, and far with angle gathers between 30° and 45°). The inversion is done using a model-based implementation with an initial earth model derived from the seismic velocity model used in the processing phase. By combining the rock physics template and the results of seismic inversion, multiple realizations of total organic content (TOC), matrix porosity, and brittleness index are generated. These parameters can be used for sweet spot detection. Lithological results can also be used as an input for basin and petroleum system modeling.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77213664","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}
Excessive heat in an oil/natural gas (ONG) drilling environment can have negative effects on workers, production levels and work efficiency. The United Arab Emirates (UAE) borders the Gulf of Oman and the Persian Gulf, and sits between Oman and Saudi Arabia. The summer temperature in the UAE can go as high as 51°C, which is extremely high for continuous outside work, especially considering that a 12-hour work shift is normal on the rigs. Due to global warming, average ambient temperatures in the summer are now generally higher than what have been experienced in the past. Although the differences are of only a few degrees, these small differences can make a big change in the work environment. Hence, companies have been trying to come up with engineering and administrative controls to reduce the effect of summer heat in this region. Photovoltaic (PV) array shades have been proposed in this paper to improve conditions for the worker. The Thermal Work Limit (TWL) has been evaluated in this study to understand the ability of PV shades in reducing thermal load on the body. TWLs have also been calculated without the shade and then compared against semi-indoor condition available on the rig. A model of PV shades has been designed to reduce the effect of heat stress keeping in mind the complexity of a rig move and other rig activities. Benefits of rooftop PV systems for area cooling are validated through previous studies and modeling. Heat flux modeling shows that solar panels can lower a roof's underside temperature by ~3°C. The PV array can also help in reducing heat loss during the cold winter nights. This paper also discusses the how this reduction of daily variability in surface temperatures under the PV shade helps to reduce worker's thermal stress.
{"title":"The Impact of PV Shades in Reducing Heat Stress in the ONG Drilling Industry in the Western Region of the United Arab Emirates","authors":"A. Siddique, C. Rodrigues, R. Simmons","doi":"10.2118/197462-ms","DOIUrl":"https://doi.org/10.2118/197462-ms","url":null,"abstract":"\u0000 Excessive heat in an oil/natural gas (ONG) drilling environment can have negative effects on workers, production levels and work efficiency. The United Arab Emirates (UAE) borders the Gulf of Oman and the Persian Gulf, and sits between Oman and Saudi Arabia. The summer temperature in the UAE can go as high as 51°C, which is extremely high for continuous outside work, especially considering that a 12-hour work shift is normal on the rigs. Due to global warming, average ambient temperatures in the summer are now generally higher than what have been experienced in the past. Although the differences are of only a few degrees, these small differences can make a big change in the work environment. Hence, companies have been trying to come up with engineering and administrative controls to reduce the effect of summer heat in this region. Photovoltaic (PV) array shades have been proposed in this paper to improve conditions for the worker. The Thermal Work Limit (TWL) has been evaluated in this study to understand the ability of PV shades in reducing thermal load on the body. TWLs have also been calculated without the shade and then compared against semi-indoor condition available on the rig. A model of PV shades has been designed to reduce the effect of heat stress keeping in mind the complexity of a rig move and other rig activities. Benefits of rooftop PV systems for area cooling are validated through previous studies and modeling. Heat flux modeling shows that solar panels can lower a roof's underside temperature by ~3°C. The PV array can also help in reducing heat loss during the cold winter nights. This paper also discusses the how this reduction of daily variability in surface temperatures under the PV shade helps to reduce worker's thermal stress.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 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":"90340815","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. B. Geri, Abdulaziz Ellafi, R. Flori, Azmi Belhaij, Ethar Hisham Khalil Al-Kamil
Nowadays, as the worldwide consumption of hydrocarbon increases, while the conventional resources beings depleted, turning point toward unconventional reservoirs is crucial to producing more additional oil and gas from their massive reserves of hydrocarbon. As a result, exploration and operation companies gain attention recently for the investment in unconventional plays, such as shale and tight formations. A recent study by the U.S. Energy Information Administration (EIA) reported that the Middle East (ME) and North Africa (NF) region holds an enormous volume of recoverable oil and gas from unconventional resources. However, the evaluation process is at the early stage, and detailed information is still confidential with a limitation of the publication in terms of unconventional reservoirs potential. The objective of this research is to provide more information and build a comprehensive review of unconventional resources to bring the shale revolution to the ME and NF region. In addition, new opportunities, challenges, and risks will be introduced based on transferring acquiring experiences and technologies that have been applied in North American shale plays to similar formations in the ME and NF region. The workflow begins with reviewing and summarizing more than 100 conference papers, journal papers, and technical reports to gather detailed data on the geological description, reservoir characterization, geomechanical property, and operation history. Furthermore, simulation works, experimental studies, and pilot tests in the United States shale plays are used to build a database using the statistic approach to summarize and identify the range of parameters. The results are compared to similar unconventional plays in the region to establish guidelines for the exploration, development, and operation processes. This paper highlights the potential opportunities to access the unlocked formations in the region that holds substantial hydrocarbon resources.
{"title":"New Opportunities and Challenges to Discover and Develop Unconventional Plays in the Middle East and North Africa: Critical Review","authors":"M. B. Geri, Abdulaziz Ellafi, R. Flori, Azmi Belhaij, Ethar Hisham Khalil Al-Kamil","doi":"10.2118/197271-ms","DOIUrl":"https://doi.org/10.2118/197271-ms","url":null,"abstract":"\u0000 Nowadays, as the worldwide consumption of hydrocarbon increases, while the conventional resources beings depleted, turning point toward unconventional reservoirs is crucial to producing more additional oil and gas from their massive reserves of hydrocarbon. As a result, exploration and operation companies gain attention recently for the investment in unconventional plays, such as shale and tight formations. A recent study by the U.S. Energy Information Administration (EIA) reported that the Middle East (ME) and North Africa (NF) region holds an enormous volume of recoverable oil and gas from unconventional resources. However, the evaluation process is at the early stage, and detailed information is still confidential with a limitation of the publication in terms of unconventional reservoirs potential. The objective of this research is to provide more information and build a comprehensive review of unconventional resources to bring the shale revolution to the ME and NF region. In addition, new opportunities, challenges, and risks will be introduced based on transferring acquiring experiences and technologies that have been applied in North American shale plays to similar formations in the ME and NF region. The workflow begins with reviewing and summarizing more than 100 conference papers, journal papers, and technical reports to gather detailed data on the geological description, reservoir characterization, geomechanical property, and operation history. Furthermore, simulation works, experimental studies, and pilot tests in the United States shale plays are used to build a database using the statistic approach to summarize and identify the range of parameters. The results are compared to similar unconventional plays in the region to establish guidelines for the exploration, development, and operation processes. This paper highlights the potential opportunities to access the unlocked formations in the region that holds substantial hydrocarbon resources.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90443181","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}
Satyadileep Dara, Yasser Alwahedi, A. Berrouk, S. Leyland, A. S. E. Nasr, I. Khan, F. Geuzebroek
This study aims at high-fidelity modeling and mechanistic optimization of gas dehydration and NGL (Natural Gas Liquids) systems of a commercial natural gas plant based in Abu Dhabi, UAE. Scope of the work includes development of models, validation of models with plant data, optimization analysis and real-time validation at the plant site. In this work, we developed a dynamic model for the gas dehydration system and a steady state model for the natural gas liquids recovery unit. An advanced process simulator that follows equation-oriented approach is employed as the modelling and optimization platform. We first show the comprehensive plant data reconciliation followed by the model validation using the operating data of the years 2016 and 2018, to ensure that the model predictions match the real plant operation. We then present how the mechanistic optimization entity result in the best operating conditions for the natural gas liquids recovery system. We also show the optimization analysis that aims at maximizing the adsorption cycle time for the dehydration unit while minimizing the total heating duty required for the regeneration of the molecular sieve beds. Optimization analysis reveals a significant increase in the annual net revenue of natural gas liquid recovery unit as a result of modifying various process operating conditions that lead to higher liquid hydrocarbon production and lower operating costs related to steam and refrigeration. Similarly, optimization analysis of the dehydration system indicates that adsorption-step time can be increased to a higher value, which results in significant reduction of regeneration costs. As a next step, we aim to carry out the validation tests on the plant site to verify and implement the model recommendations in the real plant to verify the model recommendations. We also plan to derive the set of operating guidelines that allow the operators to drive the plant towards optimal operation.
{"title":"Mechanistic Optimization of Commercial Gas Dehydration and Natural Gas Liquids Recovery Units","authors":"Satyadileep Dara, Yasser Alwahedi, A. Berrouk, S. Leyland, A. S. E. Nasr, I. Khan, F. Geuzebroek","doi":"10.2118/197734-ms","DOIUrl":"https://doi.org/10.2118/197734-ms","url":null,"abstract":"\u0000 \u0000 \u0000 This study aims at high-fidelity modeling and mechanistic optimization of gas dehydration and NGL (Natural Gas Liquids) systems of a commercial natural gas plant based in Abu Dhabi, UAE. Scope of the work includes development of models, validation of models with plant data, optimization analysis and real-time validation at the plant site.\u0000 \u0000 \u0000 \u0000 In this work, we developed a dynamic model for the gas dehydration system and a steady state model for the natural gas liquids recovery unit. An advanced process simulator that follows equation-oriented approach is employed as the modelling and optimization platform. We first show the comprehensive plant data reconciliation followed by the model validation using the operating data of the years 2016 and 2018, to ensure that the model predictions match the real plant operation. We then present how the mechanistic optimization entity result in the best operating conditions for the natural gas liquids recovery system. We also show the optimization analysis that aims at maximizing the adsorption cycle time for the dehydration unit while minimizing the total heating duty required for the regeneration of the molecular sieve beds.\u0000 \u0000 \u0000 \u0000 Optimization analysis reveals a significant increase in the annual net revenue of natural gas liquid recovery unit as a result of modifying various process operating conditions that lead to higher liquid hydrocarbon production and lower operating costs related to steam and refrigeration. Similarly, optimization analysis of the dehydration system indicates that adsorption-step time can be increased to a higher value, which results in significant reduction of regeneration costs.\u0000 As a next step, we aim to carry out the validation tests on the plant site to verify and implement the model recommendations in the real plant to verify the model recommendations. We also plan to derive the set of operating guidelines that allow the operators to drive the plant towards optimal operation.\u0000 \u0000 \u0000 \u0000","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78690573","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}
Wenyang Zhao, Ahmed Khaleefa Al-Neaimi, O. Saif, A. Abed
Reservoir management is a data driven process with an objective to achieve an optimum ultimate oil recovery. It is fundamental to obtain a proper understanding of well and reservoir performance, which can only be built based on the acquired data. Data acquisition in brownfield has been a significant challenge due to the obsolete control system, accessibility and workflows. Daily well changes is one of the key pieces of data required in routine allocation, well performance analysis, as well as simulation model updates and hence development plans. There are two major types of acquired data in the presented giant offshore brownfield, which are manually measured by operators and automatically recorded data through available SCADA system. A comprehensive data analysis has been conducted based on historical production data and reservoir surveillance data to spot the gaps and identify the opportunities for future improvement. Gaps in daily well changes data have been observed from both manually and automatically acquired data. It has been summarized into two main categories, which are data inaccurate and data missing. The inaccuracies are mainly from improper use of well change event types, inaccurate timing of data acquisition and malfunctioning of SCADA systems. Missing data includes loss of manual measurement records and insufficient utilization of SCADA data. The paper presents real examples of all these findings and a proposed workflow to enhance the data acquisition process. The concise and explicit workflow is one of the most efficient approach to tackle the hardware and manpower limitations. The importance of daily production events could not be over emphasized. Specific actions to bridge the identified gaps are crucial to achieve a sound reservoir management, maintain the sustainability, and ensure an optimum oil recovery.
{"title":"Enhancement of Routine Data Acquisition in a Giant Offshore Brownfield by Bridging Gaps Identified Through Comprehensive Data Analysis","authors":"Wenyang Zhao, Ahmed Khaleefa Al-Neaimi, O. Saif, A. Abed","doi":"10.2118/197172-ms","DOIUrl":"https://doi.org/10.2118/197172-ms","url":null,"abstract":"\u0000 Reservoir management is a data driven process with an objective to achieve an optimum ultimate oil recovery. It is fundamental to obtain a proper understanding of well and reservoir performance, which can only be built based on the acquired data. Data acquisition in brownfield has been a significant challenge due to the obsolete control system, accessibility and workflows. Daily well changes is one of the key pieces of data required in routine allocation, well performance analysis, as well as simulation model updates and hence development plans. There are two major types of acquired data in the presented giant offshore brownfield, which are manually measured by operators and automatically recorded data through available SCADA system. A comprehensive data analysis has been conducted based on historical production data and reservoir surveillance data to spot the gaps and identify the opportunities for future improvement.\u0000 Gaps in daily well changes data have been observed from both manually and automatically acquired data. It has been summarized into two main categories, which are data inaccurate and data missing. The inaccuracies are mainly from improper use of well change event types, inaccurate timing of data acquisition and malfunctioning of SCADA systems. Missing data includes loss of manual measurement records and insufficient utilization of SCADA data. The paper presents real examples of all these findings and a proposed workflow to enhance the data acquisition process. The concise and explicit workflow is one of the most efficient approach to tackle the hardware and manpower limitations. The importance of daily production events could not be over emphasized. Specific actions to bridge the identified gaps are crucial to achieve a sound reservoir management, maintain the sustainability, and ensure an optimum oil recovery.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72921704","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}
Oil and gas industry in the Russian Federation contribute more than 40% of federal budget revenues and thus its so crutial to find best solutions to its main challenges along with new opportunities for growth. One of the main challenges for the Russian oil and gas industry right now is to maintain and even develop its hydrocarbon resourse base in the regard of sustainable development of the country and its regions. According to the latest data of the State balance of natural resources of the Russian Federation from 01 of January 2016, during 140 years of oil and gas commissioning in Russia 3454 fields were discovered, among them 2462 oilfields, 572 oil and gas fields, 420 gas and gascondencate fields. Leading production area in Russia is Western-Siberian oil and gas megaprovince.
{"title":"Challenges with the Mega-Projects Development in Russia and Opportunities for International Cooperation","authors":"I. Akimova","doi":"10.2118/197711-ms","DOIUrl":"https://doi.org/10.2118/197711-ms","url":null,"abstract":"\u0000 Oil and gas industry in the Russian Federation contribute more than 40% of federal budget revenues and thus its so crutial to find best solutions to its main challenges along with new opportunities for growth. One of the main challenges for the Russian oil and gas industry right now is to maintain and even develop its hydrocarbon resourse base in the regard of sustainable development of the country and its regions.\u0000 According to the latest data of the State balance of natural resources of the Russian Federation from 01 of January 2016, during 140 years of oil and gas commissioning in Russia 3454 fields were discovered, among them 2462 oilfields, 572 oil and gas fields, 420 gas and gascondencate fields. Leading production area in Russia is Western-Siberian oil and gas megaprovince.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88417798","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. Sharma, S. Narayanan, M. Zayyan, S. Prakash, S. Raghav, Shwetha Gounder
Government of India has set an ambitious target of reducing hydrocarbon import. Increasing oil & gas production is one of the measures by which oil & gas import dependency can be reduced. Despite relatively low crude prices globally, substantial E&P activities have been carried out in the country in the last decade, which has witnessed an exponential increase in exploration of oil and gas reserves. Many new fields were discovered during this exploration campaign out of which, few are potential traps containing hydrocarbons. Kutch and Saurashtra Basin off Gujarat coast is one of the exploration fields that involves trap drilling to explore reservoir sands below. Recently for the very first time, in a decade, oil reserves have been discovered in prospective sedimentary basin of Saurashtra. (DGH India Outlook, 2017-18) Drilling in this basin is characterized by slow rate of penetration (ROP), frequent bit trips, drill string failure, and high well cost. The 12 1/4-in section in this offshore block typically drills through very hard, abrasive and thick layers of Basaltic formation (known as Deccan Trap) with unconfined compressive strength (UCS) between 18-42 kpsi. Conventional polycrystalline diamond compact (PDC) bits and roller cone (RC) bits faced extreme cutting structure damage and delivered poor ROPs in this section. In this paper, challenges of drilling approximately 2,200 m of hard and abrasive Deccan Trap in the 12.25-in section is discussed along with a proposed solution of hybrid bit design by combining conical (CDE) and ridged (RDE) diamond elements. Two new hybrid 8-bladed 16-mm bit were specifically designed for this application. The first bit drilled an interval of 952m with an average ROP of 1.9m/hr and the second bit drilled an interval of 960m with an average ROP of 1.83m/hr. Both the bits came out of the hole in good condition, thereby delivering a benchmark performance in drilling this challenging section. The runs resulted in 40% reduction in cost/meter for this section and saved 36 offshore days for the customer.
印度政府制定了减少碳氢化合物进口的雄心勃勃的目标。增加石油和天然气产量是减少石油和天然气进口依赖的措施之一。尽管全球原油价格相对较低，但在过去十年中，该国开展了大量的勘探和生产活动，这见证了石油和天然气储量的指数级增长。在这次勘探活动中发现了许多新油田，其中很少有潜在的含油气圈闭。古吉拉特邦海岸外的Kutch和Saurashtra盆地是一个涉及圈闭钻井的勘探领域，以勘探下面的储层砂。最近，在Saurashtra的潜在沉积盆地，十年来首次发现了石油储量。(DGH India Outlook, 2017-18)该盆地的钻井特点是钻进速度慢、起下钻频繁、钻柱失效、井成本高。该海上区块的12 1/4-in井段通常钻穿非常坚硬、磨粒和厚层的玄武岩地层(称为德干圈闭)，无侧限抗压强度(UCS)在18-42 kpsi之间。常规的聚晶金刚石紧凑型钻头(PDC)和滚柱钻头(RC)在该钻头中面临严重的切削结构破坏，ROPs很低。本文讨论了在12.25 In井段钻约2200 m的硬磨蚀型德干井所面临的挑战，并提出了一种结合锥形(CDE)和锯齿状(RDE)金刚石元件的混合钻头设计解决方案。为此专门设计了两种新型混合8刃16mm钻头。第一个钻头的钻距为952m，平均ROP为1.9m/hr;第二个钻头的钻距为960m，平均ROP为1.83m/hr。两种钻头都以良好的状态出井，因此在钻井这一具有挑战性的井段时提供了基准性能。该井段的每米成本降低了40%，为客户节省了36天的海上作业时间。
{"title":"Solving the Deccan Trap Drilling Challenge with Innovative Ridged and Conical Diamond Elements Technology","authors":"A. Sharma, S. Narayanan, M. Zayyan, S. Prakash, S. Raghav, Shwetha Gounder","doi":"10.2118/197735-ms","DOIUrl":"https://doi.org/10.2118/197735-ms","url":null,"abstract":"\u0000 Government of India has set an ambitious target of reducing hydrocarbon import. Increasing oil & gas production is one of the measures by which oil & gas import dependency can be reduced. Despite relatively low crude prices globally, substantial E&P activities have been carried out in the country in the last decade, which has witnessed an exponential increase in exploration of oil and gas reserves. Many new fields were discovered during this exploration campaign out of which, few are potential traps containing hydrocarbons. Kutch and Saurashtra Basin off Gujarat coast is one of the exploration fields that involves trap drilling to explore reservoir sands below. Recently for the very first time, in a decade, oil reserves have been discovered in prospective sedimentary basin of Saurashtra. (DGH India Outlook, 2017-18)\u0000 Drilling in this basin is characterized by slow rate of penetration (ROP), frequent bit trips, drill string failure, and high well cost. The 12 1/4-in section in this offshore block typically drills through very hard, abrasive and thick layers of Basaltic formation (known as Deccan Trap) with unconfined compressive strength (UCS) between 18-42 kpsi. Conventional polycrystalline diamond compact (PDC) bits and roller cone (RC) bits faced extreme cutting structure damage and delivered poor ROPs in this section. In this paper, challenges of drilling approximately 2,200 m of hard and abrasive Deccan Trap in the 12.25-in section is discussed along with a proposed solution of hybrid bit design by combining conical (CDE) and ridged (RDE) diamond elements.\u0000 Two new hybrid 8-bladed 16-mm bit were specifically designed for this application. The first bit drilled an interval of 952m with an average ROP of 1.9m/hr and the second bit drilled an interval of 960m with an average ROP of 1.83m/hr. Both the bits came out of the hole in good condition, thereby delivering a benchmark performance in drilling this challenging section. The runs resulted in 40% reduction in cost/meter for this section and saved 36 offshore days for the customer.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 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":"88420519","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}
S. Masalmeh, Mohammad Al-Hammadi, A. Farzaneh, M. Sohrabi
In recent years, low salinity flooding has attracted significant attention as a new method for improving/enhancing oil recovery for both sandstone and carbonate reservoirs. Extensive laboratory experiments investigating the effect of low salinity injection are available in the literature, which show a wide range of responses in the extra oil recovery, ranging from 0 to more than 20%. In this paper, we report experimental programs performed using cores and fluids from several reservoirs in Abu Dhabi with the objective of quantifying low salinity effect in both secondary and tertiary modes and to establish a procedure to screen reservoirs for their suitability for low salinity waterflooding. To quantify the low salinity effect, multi-rate unsteady state flooding experiments have been performed in both secondary and tertiary mode using reservoir fluids and core material at reservoir conditions of 120 C and 4000 psi. All core floods were performed using 30 cm long and 2 inch diameter core samples. In addition, fluid-fluid interaction experiments were performed using fluids from more than 20 carbonate reservoirs in Abu Dhabi. The fluid-fluid experiments were performed to measure the water in oil micro-dispersion formed upon contacting crude oil with both formation water and low salinity water in order to screen ADNOC's oil reservoirs for suitability for low salinity waterflooding. The fluid-fluid interaction experiments showed that a number of crude oil samples from carbonate reservoirs in Abu Dhabi were able to create micro-dispersion upon contact with low salinity water. These crude oils are called positive crudes in this paper. On the other hand, several crude oil samples did not show micro-dispersion upon contact with the same low salinity water, hence they are referred to as negative crude oils. Two positive crude oils and two negative crude oils have been used in the flooding experiments. The main conclusions of the study are: 1- The flooding experiments using positive crude oil samples have led to extra oil recovery upon injecting low salinity water, while the negative crude oil resulted in either no or little extra recovery, 2- The data base developed in this study is used for screening ADNOC's oil reservoirs for low salinity waterflooding based on fluid-fluid interaction and shows a significant potential of this promising EOR technology for carbonate reservoirs, and 3- The flooding experiments show up to 6.5% extra recovery in tertiary mode and up to 12.5% extra recovery in secondary mode. The study presented in this paper demonstrates that the use of fluid-fluid interaction experiments and measuring the creation of micro-dispersion upon contacting crude oil with low salinity is a robust screening method for low salinity water flooding. Moreover, this screening method can lead to significant saving in both time and cost of running low salinity flooding experiments.
{"title":"Low Salinity Water Flooding in Carbonate: Screening, Laboratory Quantification and Field Implementation","authors":"S. Masalmeh, Mohammad Al-Hammadi, A. Farzaneh, M. Sohrabi","doi":"10.2118/197314-ms","DOIUrl":"https://doi.org/10.2118/197314-ms","url":null,"abstract":"\u0000 In recent years, low salinity flooding has attracted significant attention as a new method for improving/enhancing oil recovery for both sandstone and carbonate reservoirs. Extensive laboratory experiments investigating the effect of low salinity injection are available in the literature, which show a wide range of responses in the extra oil recovery, ranging from 0 to more than 20%. In this paper, we report experimental programs performed using cores and fluids from several reservoirs in Abu Dhabi with the objective of quantifying low salinity effect in both secondary and tertiary modes and to establish a procedure to screen reservoirs for their suitability for low salinity waterflooding.\u0000 To quantify the low salinity effect, multi-rate unsteady state flooding experiments have been performed in both secondary and tertiary mode using reservoir fluids and core material at reservoir conditions of 120 C and 4000 psi. All core floods were performed using 30 cm long and 2 inch diameter core samples. In addition, fluid-fluid interaction experiments were performed using fluids from more than 20 carbonate reservoirs in Abu Dhabi. The fluid-fluid experiments were performed to measure the water in oil micro-dispersion formed upon contacting crude oil with both formation water and low salinity water in order to screen ADNOC's oil reservoirs for suitability for low salinity waterflooding.\u0000 The fluid-fluid interaction experiments showed that a number of crude oil samples from carbonate reservoirs in Abu Dhabi were able to create micro-dispersion upon contact with low salinity water. These crude oils are called positive crudes in this paper. On the other hand, several crude oil samples did not show micro-dispersion upon contact with the same low salinity water, hence they are referred to as negative crude oils. Two positive crude oils and two negative crude oils have been used in the flooding experiments. The main conclusions of the study are: 1- The flooding experiments using positive crude oil samples have led to extra oil recovery upon injecting low salinity water, while the negative crude oil resulted in either no or little extra recovery, 2- The data base developed in this study is used for screening ADNOC's oil reservoirs for low salinity waterflooding based on fluid-fluid interaction and shows a significant potential of this promising EOR technology for carbonate reservoirs, and 3- The flooding experiments show up to 6.5% extra recovery in tertiary mode and up to 12.5% extra recovery in secondary mode.\u0000 The study presented in this paper demonstrates that the use of fluid-fluid interaction experiments and measuring the creation of micro-dispersion upon contacting crude oil with low salinity is a robust screening method for low salinity water flooding. Moreover, this screening method can lead to significant saving in both time and cost of running low salinity flooding experiments.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88753020","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}
Carbonate rocks are complex in their structures and pore geometries and often exhibit a challenge in their classification and behavior. Many rock properties remain unexplained and uncertain because of improper characterization and lack of data QC. The main objective of this paper is to study flow behavior of relative permeability with different rock types in complex carbonate reservoirs. Representative core samples were selected from two major hydrocarbon reservoirs in Abu Dhabi. Rock types were identified based on textural facies, PoroPerm characteristics and capillary pressure. Porosity ranged from 15% to 25%, while permeability varied from 1 mD to 50 mD. Primary drainage and imbibition water-oil relative permeability (Kr) curves were measured by the steady-state technique using live fluids at full reservoir conditions with in-situ saturation monitoring. High-rate bump floods were designed at the end of the flooding cycles to counter capillary end effects. Aging period of 4 weeks was incorporated at the end of the drainage cycle. Robust data QC was performed on the samples, and final validation of the relative permeability was conducted by numerical simulation of the raw data and measured capillary pressure. The followed QC procedure was crucial to eliminate artefact in the relative permeability curves for proper data evaluation. The different rock types showed consistent variations in the relative permeability hysteresis and end points. Imbibition relative permeability curves showed large variations within the different rock types, where Corey exponent to oil ‘no’ increased with permeability from 3 to 5, whereas the Corey exponent to water ‘nw’ decreased with permeability and ranged from 3 to 1.5. The variations in the relative permeability curves are argued to be the result of different rock structures and pore geometries. Variations were also seen in the end-point data and showed consistent behavior with the rock types. The different carbonate rock types were identified based on geological and petrophysical properties. Higher permeability samples were grain-dominated and more heterogeneous in comparison to the lower permeability samples, which were mud-dominated rock types. Imbibition Kr curves showed larger variations than the primary drainage data, which cannot be interpreted based on wettability considerations only. The relative permeability curves have been thoroughly evaluated and QC'd based on raw data of pressure and saturation by use of numerical simulation. Such RRT-based Kr data are not abundant in the literature, and hence should serve as an important piece of information in mixed-wet carbonate reservoirs.
碳酸盐岩具有复杂的结构和孔隙几何形状，其分类和性质往往具有挑战性。由于描述不当和缺乏数据质量控制，许多岩石性质仍然无法解释和确定。本文的主要目的是研究复杂碳酸盐岩储层中不同岩石类型相对渗透率的流动特性。从阿布扎比的两个主要油气储层中选取了具有代表性的岩心样品。根据构造相、PoroPerm特征和毛管压力确定了岩石类型。孔隙度从15%到25%不等，渗透率从1 mD到50 mD不等。采用稳态技术，在全储层条件下使用活体流体测量了一次排液和渗吸水-油相对渗透率(Kr)曲线，并进行了原位饱和度监测。在注水循环结束时设计了高速率的凹凸水，以抵消毛细管末端效应。在排水周期结束时加入4周的老化期。对样品进行了稳健的数据QC，并通过对原始数据和实测毛细管压力的数值模拟对相对渗透率进行了最终验证。接下来的QC程序对于消除相对渗透率曲线中的伪影至关重要，以便进行正确的数据评估。不同岩石类型在相对渗透率滞回率和终点上表现出一致的变化。不同岩石类型的渗吸相对渗透率曲线变化较大，Corey / oil ' no '随渗透率从3增加到5，而Corey / water ' nw '随渗透率降低，范围在3 ~ 1.5之间。相对渗透率曲线的变化被认为是不同岩石结构和孔隙几何形状的结果。在终点数据中也可以看到变化，并显示出与岩石类型一致的行为。根据地质和岩石物理性质，确定了不同的碳酸盐岩类型。高渗透率样品以颗粒为主，非均质性较好，而低渗透率样品以泥质为主。渗吸Kr曲线比原始排水数据变化更大，不能仅根据润湿性来解释。基于压力和饱和度的原始数据，采用数值模拟的方法对相对渗透率曲线进行了全面的评价和质量控制。这种基于rrt的Kr数据在文献中并不丰富，因此应该作为混湿碳酸盐岩储层的重要信息。
{"title":"The Effect of Pore Geometry on Relative Permeability in Mixed-Wet Carbonate Reservoirs in Abu Dhabi","authors":"M. Dernaika, S. Masalmeh","doi":"10.2118/197427-ms","DOIUrl":"https://doi.org/10.2118/197427-ms","url":null,"abstract":"\u0000 Carbonate rocks are complex in their structures and pore geometries and often exhibit a challenge in their classification and behavior. Many rock properties remain unexplained and uncertain because of improper characterization and lack of data QC. The main objective of this paper is to study flow behavior of relative permeability with different rock types in complex carbonate reservoirs.\u0000 Representative core samples were selected from two major hydrocarbon reservoirs in Abu Dhabi. Rock types were identified based on textural facies, PoroPerm characteristics and capillary pressure. Porosity ranged from 15% to 25%, while permeability varied from 1 mD to 50 mD. Primary drainage and imbibition water-oil relative permeability (Kr) curves were measured by the steady-state technique using live fluids at full reservoir conditions with in-situ saturation monitoring. High-rate bump floods were designed at the end of the flooding cycles to counter capillary end effects. Aging period of 4 weeks was incorporated at the end of the drainage cycle. Robust data QC was performed on the samples, and final validation of the relative permeability was conducted by numerical simulation of the raw data and measured capillary pressure.\u0000 The followed QC procedure was crucial to eliminate artefact in the relative permeability curves for proper data evaluation. The different rock types showed consistent variations in the relative permeability hysteresis and end points. Imbibition relative permeability curves showed large variations within the different rock types, where Corey exponent to oil ‘no’ increased with permeability from 3 to 5, whereas the Corey exponent to water ‘nw’ decreased with permeability and ranged from 3 to 1.5. The variations in the relative permeability curves are argued to be the result of different rock structures and pore geometries. Variations were also seen in the end-point data and showed consistent behavior with the rock types.\u0000 The different carbonate rock types were identified based on geological and petrophysical properties. Higher permeability samples were grain-dominated and more heterogeneous in comparison to the lower permeability samples, which were mud-dominated rock types. Imbibition Kr curves showed larger variations than the primary drainage data, which cannot be interpreted based on wettability considerations only. The relative permeability curves have been thoroughly evaluated and QC'd based on raw data of pressure and saturation by use of numerical simulation. Such RRT-based Kr data are not abundant in the literature, and hence should serve as an important piece of information in mixed-wet carbonate reservoirs.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85213675","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}
Srimanta Chakraborty, Tapan Kidambi, Ashish Sharma, KG Sabu
This paper attempts to answer a fundamental question pertinent to fracture characterization of unconventional basement reserves using rock mechanics & petrophysics; are open fractures in basements necessary critically stressed? Evaluation of naturally occurring fractures are critical for production as well as reserves estimation. In this regard, a study well was drilled in the basement section of the Cauvery basin to explore unconventional pay zones & characterize the contributing fractures by integrated Geomechanical & Petrophysical analysis. A suite of open hole logs including the basic, acoustic and electrical borehole images were acquired and an integrated approach was taken, including geomechanical analysis to identify the contributing fractures. Standard petrophysical evaluation in basements was inconclusive and porosity quantification from fractures posed a major challenge. Image log analysis involved identification of conductive and resistive fractures in the gauged wellbore and combining Stoneley reflectivity further indicated probable open fractures. Following this, a geomechanical analysis was carried out to determine the current in-situ stress orientation/magnitudes based on observed breakouts. Finally a CSF study was done to check for fracture slip events. Based on the integrated study of Petrophysics and Geomechanics, an optimized workflow was developed and the critically stressed fractures were identified. It was found that, while some fractures strike direction was different from the present day maximum horizontal stress direction (SHmax), in general, most fractures were indeed aligned to SHmax. To check the fluid flowing capability of fracture networks, formation tester was deployed in selective zones for testing and sampling. Successful hydrocarbon sampling from selective fractures with orientation not aligned to SHmax led to the validation of the current study. The results proved that while most critically stressed/open fractures did indeed contribute to flow, a smaller fraction of the naturally occurring fractures while contributing to flow, were not necessarily aligned to the in situ orientations. The results present a discrepancy between observation and the expectation that open fractures are necessarily oriented parallel or nearly parallel to modern-day SHmax. This works highlights the fact that although paleo-stresses may influence the fracture networks, it is the contemporary in-situ stresses that truly dominate fluid flow and only through a detailed understanding of the critically stressed areas, can we come to a decisive conclusion that further improves overall recovery.
{"title":"A Novel Approach to the Geomechanical Characterization of Basement Fractures- Are Open Fractures Necessarily Critically Stressed","authors":"Srimanta Chakraborty, Tapan Kidambi, Ashish Sharma, KG Sabu","doi":"10.2118/197158-ms","DOIUrl":"https://doi.org/10.2118/197158-ms","url":null,"abstract":"\u0000 This paper attempts to answer a fundamental question pertinent to fracture characterization of unconventional basement reserves using rock mechanics & petrophysics; are open fractures in basements necessary critically stressed? Evaluation of naturally occurring fractures are critical for production as well as reserves estimation. In this regard, a study well was drilled in the basement section of the Cauvery basin to explore unconventional pay zones & characterize the contributing fractures by integrated Geomechanical & Petrophysical analysis.\u0000 A suite of open hole logs including the basic, acoustic and electrical borehole images were acquired and an integrated approach was taken, including geomechanical analysis to identify the contributing fractures. Standard petrophysical evaluation in basements was inconclusive and porosity quantification from fractures posed a major challenge. Image log analysis involved identification of conductive and resistive fractures in the gauged wellbore and combining Stoneley reflectivity further indicated probable open fractures. Following this, a geomechanical analysis was carried out to determine the current in-situ stress orientation/magnitudes based on observed breakouts. Finally a CSF study was done to check for fracture slip events.\u0000 Based on the integrated study of Petrophysics and Geomechanics, an optimized workflow was developed and the critically stressed fractures were identified. It was found that, while some fractures strike direction was different from the present day maximum horizontal stress direction (SHmax), in general, most fractures were indeed aligned to SHmax. To check the fluid flowing capability of fracture networks, formation tester was deployed in selective zones for testing and sampling. Successful hydrocarbon sampling from selective fractures with orientation not aligned to SHmax led to the validation of the current study. The results proved that while most critically stressed/open fractures did indeed contribute to flow, a smaller fraction of the naturally occurring fractures while contributing to flow, were not necessarily aligned to the in situ orientations.\u0000 The results present a discrepancy between observation and the expectation that open fractures are necessarily oriented parallel or nearly parallel to modern-day SHmax. This works highlights the fact that although paleo-stresses may influence the fracture networks, it is the contemporary in-situ stresses that truly dominate fluid flow and only through a detailed understanding of the critically stressed areas, can we come to a decisive conclusion that further improves overall recovery.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 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":"87812392","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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