Designing neutral grounding systems for Generators require careful consideration of various aspects, which are mainly related to the Generators themselves and, also with respect to other aspects of the overall system design. More importantly, when the Generators to be operated in parallel have dissimilar design, the neutral grounding design must address a whole array of issues and technical requirements. While there are solutions to mitigate these issues, some of them are not appropriate for offshore installations.
{"title":"Neutral Grounding of Dissimilar Generators in Offshore Power Systems","authors":"S. Pragasam","doi":"10.2118/193100-MS","DOIUrl":"https://doi.org/10.2118/193100-MS","url":null,"abstract":"\u0000 Designing neutral grounding systems for Generators require careful consideration of various aspects, which are mainly related to the Generators themselves and, also with respect to other aspects of the overall system design. More importantly, when the Generators to be operated in parallel have dissimilar design, the neutral grounding design must address a whole array of issues and technical requirements. While there are solutions to mitigate these issues, some of them are not appropriate for offshore installations.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89693197","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}
J. Stuker, J. Campos, D. Morbelli, J. Rivas, E. F. Delgado, Joao Assis
Scale buildup due to water production can choke oil production and require repetitive scale treatments across entire fields. In subsea wells, the common solution employs a deepwater rig to conduct either workover operations or large-volume scale inhibitor squeezes. Less frequently, coiled tubing (CT) is used from a moonpool vessel. However, current oil prices required a custom solution for subsea well treatments that was more cost effective than either a rig or a moonpool vessel. Similar previous operations successfully used 1 ¾-in. and 2-in. (44.4 mm. and 50 mm.) CT at the same time from a moonpool vessel. A remotely operated vehicle (ROV) in the open water connected the CT to the subsea safety module (SSM) through a dynamic conduit and connected the SSM to the wellhead. An engineered solution to change to 2 7/8-in. CT and use high-rate stimulation pumps was planned to deliver subsea treatments at up to 15 bbl/min. The equipment layout was designed for a multipurpose supply vessel with chemical storage tanks; to increase the available selection of vessels, the CT was designed to run overboard rather than through a moonpool. This project was initiated after accelerated scale buildup occurred because of a pressure decrease close to the bubble point, which happened when the drawdown was increased for aggressive production targets. To effectively inhibit scale in this environment, treatments required thousands of barrels of inhibitor. For wells with more-severe scale conditions, acid treatments were planned. These treatments were delivered with one complete CT package, stimulation pumping fleet, and subsea equipment, which were all installed on the spare deck space of the available vessel. A custom overboard CT deployment tower was designed. The new tower improved the dynamic bend stiffener (DBS) placement, which allowed the clump weights to be deployed with the bottomhole assembly (BHA) and simplified the rig-up. The chosen vessel worked well for the operation; however, the equipment layout and the local weather conditions combined with the response amplitude operator (RAO) of the vessel shortened the projected fatigue life of the CT. CT integrity monitoring with magnetic flux leakage (MFL) measurement was introduced here, and the vessel’s motion reference unit (MRU) provided an input to a fatigue calculator, based on the global riser analysis (GRA). The measurements and the analysis were utilized successfully to prevent CT pipe failures in the open water and deliver the required well treatments. To allow further improvements in deepwater operations, the new engineering work-flow was carefully documented.
{"title":"Step Changes in Deep, Open-Water Riserless Coiled Tubing Operations","authors":"J. Stuker, J. Campos, D. Morbelli, J. Rivas, E. F. Delgado, Joao Assis","doi":"10.2118/193090-MS","DOIUrl":"https://doi.org/10.2118/193090-MS","url":null,"abstract":"\u0000 Scale buildup due to water production can choke oil production and require repetitive scale treatments across entire fields. In subsea wells, the common solution employs a deepwater rig to conduct either workover operations or large-volume scale inhibitor squeezes. Less frequently, coiled tubing (CT) is used from a moonpool vessel. However, current oil prices required a custom solution for subsea well treatments that was more cost effective than either a rig or a moonpool vessel.\u0000 Similar previous operations successfully used 1 ¾-in. and 2-in. (44.4 mm. and 50 mm.) CT at the same time from a moonpool vessel. A remotely operated vehicle (ROV) in the open water connected the CT to the subsea safety module (SSM) through a dynamic conduit and connected the SSM to the wellhead. An engineered solution to change to 2 7/8-in. CT and use high-rate stimulation pumps was planned to deliver subsea treatments at up to 15 bbl/min. The equipment layout was designed for a multipurpose supply vessel with chemical storage tanks; to increase the available selection of vessels, the CT was designed to run overboard rather than through a moonpool.\u0000 This project was initiated after accelerated scale buildup occurred because of a pressure decrease close to the bubble point, which happened when the drawdown was increased for aggressive production targets. To effectively inhibit scale in this environment, treatments required thousands of barrels of inhibitor. For wells with more-severe scale conditions, acid treatments were planned. These treatments were delivered with one complete CT package, stimulation pumping fleet, and subsea equipment, which were all installed on the spare deck space of the available vessel.\u0000 A custom overboard CT deployment tower was designed. The new tower improved the dynamic bend stiffener (DBS) placement, which allowed the clump weights to be deployed with the bottomhole assembly (BHA) and simplified the rig-up. The chosen vessel worked well for the operation; however, the equipment layout and the local weather conditions combined with the response amplitude operator (RAO) of the vessel shortened the projected fatigue life of the CT.\u0000 CT integrity monitoring with magnetic flux leakage (MFL) measurement was introduced here, and the vessel’s motion reference unit (MRU) provided an input to a fatigue calculator, based on the global riser analysis (GRA). The measurements and the analysis were utilized successfully to prevent CT pipe failures in the open water and deliver the required well treatments. To allow further improvements in deepwater operations, the new engineering work-flow was carefully documented.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89939107","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}
Nasr Awad, Ashraf Abdel Sattar, M. Sheha, A. Moustafa, M. Vazquez, A. Farid, Alaa Mohamedien, Mohamed Manaa
Perforating a gas well efficiently requires applying technological advances to carry out a safe operation without compromising well productivity. In this paper, is discussed the application of a pre- job plan methodology called perforating well on paper to the perforation operation of SITRA 3-4. This methodology involved tension simulation, perforating gun and charge selection, conveyance hardware optimization, best underbalance value selection, as well as modeling of gun shock, gun movement and reservoir behavior when shooting multiple zones with different pressure regimes. Simulation methodology was performed as well real time during the perforating job to optimize static and flowing underbalance without compromising the safety of the operation and maximizing production gains.
{"title":"Novel Perforating Design Delivers Production Targets Safely and Efficiently in Gas Producing Wells","authors":"Nasr Awad, Ashraf Abdel Sattar, M. Sheha, A. Moustafa, M. Vazquez, A. Farid, Alaa Mohamedien, Mohamed Manaa","doi":"10.2118/193223-MS","DOIUrl":"https://doi.org/10.2118/193223-MS","url":null,"abstract":"\u0000 Perforating a gas well efficiently requires applying technological advances to carry out a safe operation without compromising well productivity.\u0000 In this paper, is discussed the application of a pre- job plan methodology called perforating well on paper to the perforation operation of SITRA 3-4.\u0000 This methodology involved tension simulation, perforating gun and charge selection, conveyance hardware optimization, best underbalance value selection, as well as modeling of gun shock, gun movement and reservoir behavior when shooting multiple zones with different pressure regimes. Simulation methodology was performed as well real time during the perforating job to optimize static and flowing underbalance without compromising the safety of the operation and maximizing production gains.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75999121","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}
Human performance principles, which are well developed in aviation and healthcare, still represent an emerging science within the oil and gas industry. The industry managed to significantly reduce injuries over the last decade with multiple programs ranging from HSE Leadership to Behavior-Based Safety to the point when the incidents plateaued according to IOGP and IADC incident statistics. This triggered a deeper look into human performance best practices and their applicability within the oil and gas sector. This paper aims to provide an alternative approach to adopt Human Performance science to the dynamic operations risk assessment process within an Oilfield Services Company. After the analysis of the existing human reliability assessment tools, a decision was made to adopt a human performance tool known as Human Error Assessment & Reduction Technique (HEART) into a service provider’s risk assessment process with a primary focus on Error Producing Conditions (EPC). An internal survey was undertaken to define Error Producint Condition, which are most relevant to the dynamic nature of oil and gas services operations and couple them with the Reasons’s performance modes and their effect on error appearance. This approach allowed to significantly simplify the risk assessment process and adequately focus on key factors known to produce conditions for human error. This naturally integrated into our existing qualitative risk assessment to recalculate the overall risk of a certain task and enhanced workers’ ability to recognize potentially dangerous external and internal factors. The field tests of the improved human performance risk assessments reshaped the standard risk assessment practices, moving the focus to and targeting the inherent unreliability of the task as a result of error producing conditions caused by unavoidable human interactions within the complex systems. This approach proved effective in improving the overall understanding of dynamic human reliability related risks among the front line employees by around 30%. The hypothesis is that by introducing key human performance factors to the day-to-day risk assessment will help build awareness of human factors and their relationship to the probability of an existing risk. At the same time, utilizing an already effective system – risk assessment – to introduce human factors methods will help avoid the complexity associated with its implementation of an additional human reliability tool and still get the benefit of key elements of a well-established method. This approach has undertaken to combine two existing effective systems: a standard risk assessment with integrated human factors under a customized umbrella fully suitable for Oilfield Service Company’s work specifics. This paper provides insights on how human factors can impact the level of risk and outlines the control measures targeted at such factors that can be missed if a standard risk assessment is applied.
{"title":"Proactive Application of Human Performance Science in Risk Assessment Process within Dynamic Operations of an Oilfield Service Provider","authors":"A. Yasseen, S. Peresypkin","doi":"10.2118/193082-MS","DOIUrl":"https://doi.org/10.2118/193082-MS","url":null,"abstract":"\u0000 Human performance principles, which are well developed in aviation and healthcare, still represent an emerging science within the oil and gas industry. The industry managed to significantly reduce injuries over the last decade with multiple programs ranging from HSE Leadership to Behavior-Based Safety to the point when the incidents plateaued according to IOGP and IADC incident statistics. This triggered a deeper look into human performance best practices and their applicability within the oil and gas sector. This paper aims to provide an alternative approach to adopt Human Performance science to the dynamic operations risk assessment process within an Oilfield Services Company. After the analysis of the existing human reliability assessment tools, a decision was made to adopt a human performance tool known as Human Error Assessment & Reduction Technique (HEART) into a service provider’s risk assessment process with a primary focus on Error Producing Conditions (EPC). An internal survey was undertaken to define Error Producint Condition, which are most relevant to the dynamic nature of oil and gas services operations and couple them with the Reasons’s performance modes and their effect on error appearance. This approach allowed to significantly simplify the risk assessment process and adequately focus on key factors known to produce conditions for human error. This naturally integrated into our existing qualitative risk assessment to recalculate the overall risk of a certain task and enhanced workers’ ability to recognize potentially dangerous external and internal factors.\u0000 The field tests of the improved human performance risk assessments reshaped the standard risk assessment practices, moving the focus to and targeting the inherent unreliability of the task as a result of error producing conditions caused by unavoidable human interactions within the complex systems. This approach proved effective in improving the overall understanding of dynamic human reliability related risks among the front line employees by around 30%. The hypothesis is that by introducing key human performance factors to the day-to-day risk assessment will help build awareness of human factors and their relationship to the probability of an existing risk. At the same time, utilizing an already effective system – risk assessment – to introduce human factors methods will help avoid the complexity associated with its implementation of an additional human reliability tool and still get the benefit of key elements of a well-established method.\u0000 This approach has undertaken to combine two existing effective systems: a standard risk assessment with integrated human factors under a customized umbrella fully suitable for Oilfield Service Company’s work specifics. This paper provides insights on how human factors can impact the level of risk and outlines the control measures targeted at such factors that can be missed if a standard risk assessment is applied.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80903759","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}
ADNOC Gas Processing, one of the world’s largest gas processing companies, operates 5 large sites (includes 26 processing trains and an NGL distillation complex at Ruwais) and manages 3000+ kilometre pipeline distribution network which has a capacity of 8 billion standard cubic feet of gas per day. Both the country’s electricity and water supplies are dependent on ADNOC Gas Processing’s continuous operation and the safety of people working on or near their assets is dependent on their safe operation. The ADNOC Health Safety and Environment (HSE) Code of Practice (COP) requires that ADNOC Gas Processing implements a systematic approach to HSE which is consistent with the ADNOC HSE Management System. Therefore the ADNOC Gas Processing HSE Management Manual (HSEMM) serves as the ADNOC Gas Processing HSE Management System (HSEMS) and describes expectations in line with the ADNOC COP and provides an overview of how these expectations are met. In addition to ADNOC CoP Requirements, Process Safety Expectations from ADNOC Gas Processing’s Process Safety Management Standard are included in the ADNOC Gas Processing HSE Management Manual (HSEMM).
{"title":"Managing Human Barriers through Operating Integrity Management","authors":"Hemant Kumar Balakrishnan","doi":"10.2118/193033-MS","DOIUrl":"https://doi.org/10.2118/193033-MS","url":null,"abstract":"\u0000 ADNOC Gas Processing, one of the world’s largest gas processing companies, operates 5 large sites (includes 26 processing trains and an NGL distillation complex at Ruwais) and manages 3000+ kilometre pipeline distribution network which has a capacity of 8 billion standard cubic feet of gas per day. Both the country’s electricity and water supplies are dependent on ADNOC Gas Processing’s continuous operation and the safety of people working on or near their assets is dependent on their safe operation.\u0000 The ADNOC Health Safety and Environment (HSE) Code of Practice (COP) requires that ADNOC Gas Processing implements a systematic approach to HSE which is consistent with the ADNOC HSE Management System. Therefore the ADNOC Gas Processing HSE Management Manual (HSEMM) serves as the ADNOC Gas Processing HSE Management System (HSEMS) and describes expectations in line with the ADNOC COP and provides an overview of how these expectations are met.\u0000 In addition to ADNOC CoP Requirements, Process Safety Expectations from ADNOC Gas Processing’s Process Safety Management Standard are included in the ADNOC Gas Processing HSE Management Manual (HSEMM).","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"77 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77663778","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. Onaisi, L. Zinsmeister, C. Urbanczyk, A. Garnier, Jean-Yves Lansot
It is well known that cement shrinks during hydration leading to a drop of stresses in the cement sheath below the hydrostatic pressure applied right after cement placement. This phenomenon might affect the integrity of the cement sheath under pressure and thermal loads taking place during the well lifecycle. A standard practice in the industry is to add to the cement expansion additives to balance the effects of shrinkage. When designing the cement recipe, a recurrent question is the percentage of additives by weight of cement (BWC) that needs to be added to fulfill technical requirements, yet at the lowest possible cost. It is believed for example that exaggerated expansion could be counterproductive because of the development of too high stresses that might fracture the set cement. Another important question is whether expansion can be activated without external water or pore pressure supply, which is the case if the cement is in contact with a shale formation or it is isolated from the reservoir by an impermeable mud cake or if the cement is placed between two casings. Cement permeability itself becomes an important parameter if the activation of expansion do require a source of water and/or pore pressure supply. The API RP 10B-5 (ISO 10426-5) recommends to use either the annular ring test or the membrane test to measure shrinkage/expansion of well cement formulations at atmospheric pressure. In the case of the ring, the cement specimen is in direct contact with water while in the membrane test it is not. Many companies modified the protocol of ring test by applying a water pressure to mimic the hydrostatic well pressure and to be able to increase the temperature. The ring test can be considered to simulate the case of a cement isolating a permeable reservoir and the membrane test the case of a cement placed either in front of an impermeable formation (shale for instance) or between two casings. In practice, most of the time, expansion is evaluated in the ring setup without paying attention to its validity outside the conditions of this test. In the recent years, Total has developed advanced cement testing devices that allow continuous measurement during hydration of volumetric strains, e.g. shrinkage/expansion, as well as water supply under realistic stress, drainage and temperature conditions. For the purpose of the work presented in this paper, three types of testing protocols were performed: Drained tests in which the pore pressure is kept constant and the resulting in water inflow/outflow is monitored.Undrained tests meaning zero water flow inducing changes of pore pressure that can be monitored by pressure sensors put at the two ends of the tested sample.Hybrid tests starting by an undrained followed by a drained phase with the aim to test the cement under various levels of effective pressure, defined as the difference between confining and pore pressures. In parallel, API annular ring tests, with and without pressure, were perfo
众所周知，水泥在水化过程中会收缩，导致水泥环中的应力下降，低于水泥注入后施加的静水压力。在井的整个生命周期中，这种现象可能会影响水泥环在压力和热载荷作用下的完整性。行业的标准做法是在水泥中加入膨胀添加剂来平衡收缩的影响。在设计水泥配方时，一个反复出现的问题是，为了满足技术要求，在尽可能低的成本下，需要添加的水泥添加剂的重量百分比(BWC)。例如，人们认为过度膨胀可能会适得其反，因为过高的应力可能会破坏水泥。另一个重要的问题是，在没有外部水或孔隙压力供应的情况下，如果水泥与页岩地层接触，或者水泥被不透水的泥饼与油藏隔离，或者水泥被放置在两个套管之间，是否可以激活膨胀。如果激活膨胀确实需要水源和/或孔隙压力供应，水泥渗透率本身就成为一个重要参数。API RP 10B-5 (ISO 10426-5)建议使用环环测试或膜测试来测量井水泥配方在大气压下的收缩/膨胀。在环试验中，水泥试样与水直接接触，而在膜试验中则不是。许多公司修改了环测试方案，通过施加水压来模拟静水井压力，并能够提高温度。环测试可以被认为是模拟水泥隔离可渗透油藏的情况，而膜测试则是模拟水泥位于不渗透地层(例如页岩)前面或两个套管之间的情况。在实践中，大多数情况下，膨胀是在环形设置中评估的，而不关注其在该测试条件之外的有效性。近年来，道达尔开发了先进的水泥测试设备，可以在水化过程中连续测量体积应变，例如收缩/膨胀，以及在实际应力、排水和温度条件下的供水。为了完成本文的工作，进行了三种类型的测试方案:排水测试，其中孔隙压力保持恒定，并监测由此产生的水流入/流出。不排水试验是指零水流引起孔隙压力的变化，这种变化可以通过放置在被测样品两端的压力传感器来监测。混合测试从不排水阶段开始，然后是排水阶段，目的是在不同水平的有效压力下测试水泥，有效压力定义为围压和孔隙压力之间的差异。同时，为了进行比较，进行了有压力和无压力的API环环测试。并根据试验结果对理论模型进行了修正。这种方法使人们对膨胀的发展方式有了新的认识，最重要的是，它对有效应力和供水的敏感性在水泥水化过程中以及之后可能发生的显著变化，并取决于胶结地层的力学特性。结果清楚地表明，API测试不足以完全表征水泥环的收缩和膨胀。本文的目的是首先描述先进的实验装置，并将其结果与API推荐的测试结果进行比较。然后，提出了一个理论模型，模拟水化过程和随后的收缩和膨胀。将表明，为了再现在实验室测试中观察到的行为和各种测试方案之间的差异，有必要引入膨胀力的概念，并考虑孔隙压力和供水。在此基础上，该模型将能够预测膨胀添加剂的效率，并优化膨胀添加剂的BWC百分比，如果认为膨胀在当地的井下条件下是有效的。
{"title":"Is Post Expansion Measured by Standard Ring Experiment Meaningful for Cement Sheath Integrity?","authors":"A. Onaisi, L. Zinsmeister, C. Urbanczyk, A. Garnier, Jean-Yves Lansot","doi":"10.2118/192718-ms","DOIUrl":"https://doi.org/10.2118/192718-ms","url":null,"abstract":"\u0000 It is well known that cement shrinks during hydration leading to a drop of stresses in the cement sheath below the hydrostatic pressure applied right after cement placement. This phenomenon might affect the integrity of the cement sheath under pressure and thermal loads taking place during the well lifecycle.\u0000 A standard practice in the industry is to add to the cement expansion additives to balance the effects of shrinkage. When designing the cement recipe, a recurrent question is the percentage of additives by weight of cement (BWC) that needs to be added to fulfill technical requirements, yet at the lowest possible cost. It is believed for example that exaggerated expansion could be counterproductive because of the development of too high stresses that might fracture the set cement.\u0000 Another important question is whether expansion can be activated without external water or pore pressure supply, which is the case if the cement is in contact with a shale formation or it is isolated from the reservoir by an impermeable mud cake or if the cement is placed between two casings. Cement permeability itself becomes an important parameter if the activation of expansion do require a source of water and/or pore pressure supply.\u0000 The API RP 10B-5 (ISO 10426-5) recommends to use either the annular ring test or the membrane test to measure shrinkage/expansion of well cement formulations at atmospheric pressure. In the case of the ring, the cement specimen is in direct contact with water while in the membrane test it is not. Many companies modified the protocol of ring test by applying a water pressure to mimic the hydrostatic well pressure and to be able to increase the temperature. The ring test can be considered to simulate the case of a cement isolating a permeable reservoir and the membrane test the case of a cement placed either in front of an impermeable formation (shale for instance) or between two casings. In practice, most of the time, expansion is evaluated in the ring setup without paying attention to its validity outside the conditions of this test.\u0000 In the recent years, Total has developed advanced cement testing devices that allow continuous measurement during hydration of volumetric strains, e.g. shrinkage/expansion, as well as water supply under realistic stress, drainage and temperature conditions. For the purpose of the work presented in this paper, three types of testing protocols were performed: Drained tests in which the pore pressure is kept constant and the resulting in water inflow/outflow is monitored.Undrained tests meaning zero water flow inducing changes of pore pressure that can be monitored by pressure sensors put at the two ends of the tested sample.Hybrid tests starting by an undrained followed by a drained phase with the aim to test the cement under various levels of effective pressure, defined as the difference between confining and pore pressures.\u0000 In parallel, API annular ring tests, with and without pressure, were perfo","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"57 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86889207","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 annual cost of steel corrosion is estimated to be $2,500 billon across the globe (Small). Sulphate Reducing Bacteria (SRB) is one of the most implicated Bacteria in internal corrosion failures worldwide. Currently the method for controlling Sulphate Reducing Bacteria (SRB) by the International Oil and Gas Companies (IOCs) to mitigate the risk of Microbiological Induced Corrosion (MIC) on their wet treated or untreated crude oil transmission pipelines or tanks is by either batch treatment or slug treatment by injecting biocide between two pigs or direct injection through quill in the absence of online facilities for launching multiple pigs simultaneously. The international best practise for the control of SRB is to kill the bacteria in-situ and prevent the contamination of downstream equipment and piping. To increase killing effectiveness and prevent resistant strains of SRB from been developed, biocides are alternated based on planned treatment frequency determine by the corrosion engineer or corrosion consultant that developed the programme. Time to kill test is conducted in the field to determine the concentration and time to kill the planktonic bacteria, however, determining the time to kill for sessile SRB is often difficult to achieve except slug between two pigs is utilised to create maximum contact with SRB in-situ. Other parameters to be considered when developing a biocide treatment program are the historical data of the pipeline, the mixed flow velocity, Gas Oil Ratio (GOR), Water Cut (Base Sediment) and Water (BS&W), Pipeline topography, pipeline significance factor, maximum pitting rate, maximum uniform corrosion rate and historical leak history. The method of assessing the risk due to SRB for static equipment (tanks or pipelines) varies from company to company and there is no universally acceptable standard on what to consider as bench mark for best and effective treatment. In addition, the kind of SRB (Sessile or Planktonic) to be monitored in-situ has also been debated by industry stake holders and corrosion practitioners. Whilst some operators monitor only planktonic in water phase, others monitor sessile growth via installed bio-probes and planktonic from oil field water sample microbiological analysis. This paper present current practise, identify the gaps in the practise and propose risk based approach to SRB characterization to enhance biocide treatment effectiveness and monitoring. It is the intention of the authors to spur a debate that will lead to the development of best practise in biocide treatment strategy by the International Oil and Gas Companies (IOCs). The authors are of the opinion that improving treatment strategy with SRB characterization using risk based approach will result in efficiency of treatment in addition to substantial cost optimisation to the tune of 20% OPEX and 25% CAPEX.
{"title":"Sulphate Reducing Bacteria SRB Control and Risk Based SRB Severity Ranking","authors":"J. I. Emmanuel, T. T. Shaapere","doi":"10.2118/192938-MS","DOIUrl":"https://doi.org/10.2118/192938-MS","url":null,"abstract":"\u0000 The annual cost of steel corrosion is estimated to be $2,500 billon across the globe (Small).\u0000 Sulphate Reducing Bacteria (SRB) is one of the most implicated Bacteria in internal corrosion failures worldwide. Currently the method for controlling Sulphate Reducing Bacteria (SRB) by the International Oil and Gas Companies (IOCs) to mitigate the risk of Microbiological Induced Corrosion (MIC) on their wet treated or untreated crude oil transmission pipelines or tanks is by either batch treatment or slug treatment by injecting biocide between two pigs or direct injection through quill in the absence of online facilities for launching multiple pigs simultaneously.\u0000 The international best practise for the control of SRB is to kill the bacteria in-situ and prevent the contamination of downstream equipment and piping. To increase killing effectiveness and prevent resistant strains of SRB from been developed, biocides are alternated based on planned treatment frequency determine by the corrosion engineer or corrosion consultant that developed the programme. Time to kill test is conducted in the field to determine the concentration and time to kill the planktonic bacteria, however, determining the time to kill for sessile SRB is often difficult to achieve except slug between two pigs is utilised to create maximum contact with SRB in-situ.\u0000 Other parameters to be considered when developing a biocide treatment program are the historical data of the pipeline, the mixed flow velocity, Gas Oil Ratio (GOR), Water Cut (Base Sediment) and Water (BS&W), Pipeline topography, pipeline significance factor, maximum pitting rate, maximum uniform corrosion rate and historical leak history.\u0000 The method of assessing the risk due to SRB for static equipment (tanks or pipelines) varies from company to company and there is no universally acceptable standard on what to consider as bench mark for best and effective treatment. In addition, the kind of SRB (Sessile or Planktonic) to be monitored in-situ has also been debated by industry stake holders and corrosion practitioners. Whilst some operators monitor only planktonic in water phase, others monitor sessile growth via installed bio-probes and planktonic from oil field water sample microbiological analysis.\u0000 This paper present current practise, identify the gaps in the practise and propose risk based approach to SRB characterization to enhance biocide treatment effectiveness and monitoring. It is the intention of the authors to spur a debate that will lead to the development of best practise in biocide treatment strategy by the International Oil and Gas Companies (IOCs). The authors are of the opinion that improving treatment strategy with SRB characterization using risk based approach will result in efficiency of treatment in addition to substantial cost optimisation to the tune of 20% OPEX and 25% CAPEX.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81710013","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}
Several onshore concessions, currently under exploration by ADNOC, consist of tight laterally variable reservoirs that pose a significant challenge during the evaluation phase of exploration. Most tight hydrocarbon-bearing formations require fracture stimulation. As such, the evaluation phase of these resources comprises not only the characterisation of reservoir rock properties using petrophysical analysis but, crucially, the construction of 1-D Mechanical Earth Models which underpin the identification of stimulation intervals for both vertical and horizontal well completions. The 1-D MEMs discussed here were provided by different vendors and have been calibrated against interval pressure tests, that included standard "wet" straddle packer microfractures and novel "dry" Sleeve-Fracture tests. The microfracture test data used to calibrate the MEMs were obtained from different depth intervals in onshore Abu Dhabi E&A wells and exhibit non-ideal pressure decline "shut-in" behavior. This required re-analysis using different interpretation methods to identify the lower bound fracture closure pressures and minimum stress magnitudes. The identification of stimulation intervals from the 1-D MEMs highlighted the uncertainty in the minimum stress magnitude estimations from both the log-based models, and the microfrac interpretations. The uncertainty in the log-based minimum horizontal stresses can exceed 0.15 psi/ft (>17%), even after calibration with the microfracture tests. The uncertainty in the fracture closure pressure obtained from the microfracture test can also be as large as 1,600 psi (0.22 psi/ft and 30%). The identification of the sources of the uncertainty, their quantification and the re-evaluation of microfracture tests fed directly into updated 1-D MEMs, which led to improved recommendations for optimised injectivity tests and acid fracturing treatments. This, in turn, has translated into a successful fluid sampling and production appraisal programme.
{"title":"Characterising and Defining Stimulation Zones in Tight Formations for Appraisal Wells Onshore U.A.E with the Aid of Integrated Standard and Novel Stress Determination Methods","authors":"Neil Doucette, M. Ziller, T. Addis","doi":"10.2118/193032-MS","DOIUrl":"https://doi.org/10.2118/193032-MS","url":null,"abstract":"\u0000 Several onshore concessions, currently under exploration by ADNOC, consist of tight laterally variable reservoirs that pose a significant challenge during the evaluation phase of exploration.\u0000 Most tight hydrocarbon-bearing formations require fracture stimulation. As such, the evaluation phase of these resources comprises not only the characterisation of reservoir rock properties using petrophysical analysis but, crucially, the construction of 1-D Mechanical Earth Models which underpin the identification of stimulation intervals for both vertical and horizontal well completions. The 1-D MEMs discussed here were provided by different vendors and have been calibrated against interval pressure tests, that included standard \"wet\" straddle packer microfractures and novel \"dry\" Sleeve-Fracture tests. The microfracture test data used to calibrate the MEMs were obtained from different depth intervals in onshore Abu Dhabi E&A wells and exhibit non-ideal pressure decline \"shut-in\" behavior. This required re-analysis using different interpretation methods to identify the lower bound fracture closure pressures and minimum stress magnitudes.\u0000 The identification of stimulation intervals from the 1-D MEMs highlighted the uncertainty in the minimum stress magnitude estimations from both the log-based models, and the microfrac interpretations. The uncertainty in the log-based minimum horizontal stresses can exceed 0.15 psi/ft (>17%), even after calibration with the microfracture tests. The uncertainty in the fracture closure pressure obtained from the microfracture test can also be as large as 1,600 psi (0.22 psi/ft and 30%).\u0000 The identification of the sources of the uncertainty, their quantification and the re-evaluation of microfracture tests fed directly into updated 1-D MEMs, which led to improved recommendations for optimised injectivity tests and acid fracturing treatments. This, in turn, has translated into a successful fluid sampling and production appraisal programme.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"152 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86223205","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}
For natural gas sweetening, amine based chemical absorption is the most used process. However, large energy requirements in the regeneration of the amine solvent makes this process energy intensive. The concept of heat pump assisted distillation has been known to reduce energy requirements in distillation processes. In this work, we study, simulate and analyze four different configurations for the regeneration of amine employing the concept of heat pump. The studied configurations are based on the concepts of Mechanical Vapor Recompression (MVR) and Self-Heat Recuperation (SHR). The configurations were simulated using Aspen HYSYS software. The configurations were mainly analyzed by comparing their overall energy consumption, overall cooling energy and operational costs. The developed configurations were also compared with the conventional regeneration unit design. The results show that the best obtained configuration uses both MVR and SHR based design of heat pump. The SHR aspect related to further preheating of the feed stream. This resulted in savings in the overall energy consumption, cooling energy and operational costs were 10.11%, 10.92% and 8.28% (savings of about 41,000 $/yr) as compared to a conventional regeneration unit design for this configuration.
{"title":"Process Synthesis and Simulation of Amine Solvent Regeneration in Natural Gas Sweetening Units Using Heat Pump Assisted Configurations","authors":"A. Jagannath, A. Almansoori","doi":"10.2118/192745-MS","DOIUrl":"https://doi.org/10.2118/192745-MS","url":null,"abstract":"\u0000 For natural gas sweetening, amine based chemical absorption is the most used process. However, large energy requirements in the regeneration of the amine solvent makes this process energy intensive. The concept of heat pump assisted distillation has been known to reduce energy requirements in distillation processes. In this work, we study, simulate and analyze four different configurations for the regeneration of amine employing the concept of heat pump. The studied configurations are based on the concepts of Mechanical Vapor Recompression (MVR) and Self-Heat Recuperation (SHR). The configurations were simulated using Aspen HYSYS software. The configurations were mainly analyzed by comparing their overall energy consumption, overall cooling energy and operational costs. The developed configurations were also compared with the conventional regeneration unit design. The results show that the best obtained configuration uses both MVR and SHR based design of heat pump. The SHR aspect related to further preheating of the feed stream. This resulted in savings in the overall energy consumption, cooling energy and operational costs were 10.11%, 10.92% and 8.28% (savings of about 41,000 $/yr) as compared to a conventional regeneration unit design for this configuration.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"72 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87519464","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}
Rasim Serdar Rodoplu, A. Tiss, Asif Bin Adnan, Ahmed Siham
15K Open Hole Multi Stage Fracturing (OH MSF) completion was successfully implemented with the goal of hydrocarbon production at sustained rates from tight HPHT gas formation and to diversify technology portfolio to address similar challenges. OH MSF completion technology has been globally proven successful in enhancing the well design, stimulation efficiency and production. As more wells are being drilled deeper, longer and in more challenging formations, the OH MSF technology also evolved resulting in introduction of a HPHT – 15K psi working pressure - MSF system. The technology had to overcome many challenges before it could be deployed. Pre-deployment stages of this technology have two main components;Standard tool design including material selection, NACE compatibility, dimensions, API standard compliance, testing, and prototypingCompletion construction design, installation challenges & force analysis The candidate well was drilled horizontally to achieve enough formation contact in a tight HPHT formation. Wells with similar poor development have been seen to require upwards of current OH MSF completions reaching to their limits of 10K psi differential pressure downhole to successfully complete with proppant fracturing. Candidate well was planned to be trial tested with 15K OH MSF completion to solve the challenge of high breakdown pressures and to capitalize on the greater productivity of open hole completions across this tight HPHT formation. The proppant fracturing operations resulted in the successful completion of five stages of proppant fracturing in this formation. A total of more than 1.2 million lbs of proppant was placed during hydraulic fracturing operations exceeding 10K differential pressure across the MSF completion. The well showed an excellent post frac flowback results exceeding expectations. Previous wellbore completion pressure limitations in many instances acted as a constraint to reach job objectives has been surmounted. The implementation of 15K OH MSF completion system has helped pave the way to attend tighter formations in an efficient and cost effective manner. Engineering approach and design to develop this completion system and utilization in the right candidate confirmed the benefit of the completion for field development options. The implementation of this technology will improve and diversify the efforts in exploiting tight HPHT formations.
{"title":"Successful Implementation of 15K Open Hole Multi Stage Fracturing Completion","authors":"Rasim Serdar Rodoplu, A. Tiss, Asif Bin Adnan, Ahmed Siham","doi":"10.2118/193114-MS","DOIUrl":"https://doi.org/10.2118/193114-MS","url":null,"abstract":"\u0000 15K Open Hole Multi Stage Fracturing (OH MSF) completion was successfully implemented with the goal of hydrocarbon production at sustained rates from tight HPHT gas formation and to diversify technology portfolio to address similar challenges.\u0000 OH MSF completion technology has been globally proven successful in enhancing the well design, stimulation efficiency and production. As more wells are being drilled deeper, longer and in more challenging formations, the OH MSF technology also evolved resulting in introduction of a HPHT – 15K psi working pressure - MSF system. The technology had to overcome many challenges before it could be deployed. Pre-deployment stages of this technology have two main components;Standard tool design including material selection, NACE compatibility, dimensions, API standard compliance, testing, and prototypingCompletion construction design, installation challenges & force analysis\u0000 The candidate well was drilled horizontally to achieve enough formation contact in a tight HPHT formation. Wells with similar poor development have been seen to require upwards of current OH MSF completions reaching to their limits of 10K psi differential pressure downhole to successfully complete with proppant fracturing. Candidate well was planned to be trial tested with 15K OH MSF completion to solve the challenge of high breakdown pressures and to capitalize on the greater productivity of open hole completions across this tight HPHT formation.\u0000 The proppant fracturing operations resulted in the successful completion of five stages of proppant fracturing in this formation. A total of more than 1.2 million lbs of proppant was placed during hydraulic fracturing operations exceeding 10K differential pressure across the MSF completion. The well showed an excellent post frac flowback results exceeding expectations. Previous wellbore completion pressure limitations in many instances acted as a constraint to reach job objectives has been surmounted.\u0000 The implementation of 15K OH MSF completion system has helped pave the way to attend tighter formations in an efficient and cost effective manner. Engineering approach and design to develop this completion system and utilization in the right candidate confirmed the benefit of the completion for field development options. The implementation of this technology will improve and diversify the efforts in exploiting tight HPHT formations.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82363300","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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