Suhaib Ghatrifi, Ghadna Sulaimi, Maria Jimenez Chavez, Ayca Sivrikoz
Water Shut-Off (WSO) actions are remedial activities that are being implemented in the heavy oil N Field, with the objective of reducing the water inflow of the well by closing zones which are major contributor to the high water cut. WSO are commonly executed as a mitigation action in operating wells with previous economic value. The purpose of this study is to develop a thorough knowledge of the rate of success of WSO activities linked to the time of WSO implementation, type of well (either horizontal or vertical) and the presence or lack of PLT (Production Log Test). Success was evaluated by reviewing the net oil production rate before and after WSO activity with the gained net oil rate being converted to US Dollars. There is no significant difference found in the success ratios between horizontal wells and verticals. However, in the horizontal wells, 74% of the successful ones were the heel shut-offs. WSO activities are found to have a success rate of 100% if the activity is implemented within the first year of the start of high water cut. Moreover, wells with WSO implementation within the first three years of observing high water-cut have a success rate of 65%. Noticeably, the success rate decreased dramatically with time, with wells having high water-cut for seven years and up to eleven years to the time of WSO implementation. These wells show success rates of 50% and 33% for seven and eleven years respectively. A numerical sector model and well model were created to explain these findings. During oil production because of a localized decrease in pressure, the water-oil interface may rise up and deform into a conical shape near the well. This phenomenon is known as ‘water coning’. At the time of water breakthrough, the cone is observed to be narrower than more advanced stages when the water cut has risen to higher levels. At these times, the cone has broadened and, depending on spacing between adjacent wells, has lifted the overall level of the oil/water interface, decreasing the distance between the wellbore and the water. As a result, water shutoff becomes less effective with time. It is recommended to start WSO activities on wells within the first three years of high water-cut indications. In case there is no PLT or other data, heel shutoff for the horizontal wells have a better success rate.
{"title":"Oil Gain from Successful Water Shut-Off Strategy","authors":"Suhaib Ghatrifi, Ghadna Sulaimi, Maria Jimenez Chavez, Ayca Sivrikoz","doi":"10.2118/193245-MS","DOIUrl":"https://doi.org/10.2118/193245-MS","url":null,"abstract":"\u0000 Water Shut-Off (WSO) actions are remedial activities that are being implemented in the heavy oil N Field, with the objective of reducing the water inflow of the well by closing zones which are major contributor to the high water cut. WSO are commonly executed as a mitigation action in operating wells with previous economic value. The purpose of this study is to develop a thorough knowledge of the rate of success of WSO activities linked to the time of WSO implementation, type of well (either horizontal or vertical) and the presence or lack of PLT (Production Log Test).\u0000 Success was evaluated by reviewing the net oil production rate before and after WSO activity with the gained net oil rate being converted to US Dollars.\u0000 There is no significant difference found in the success ratios between horizontal wells and verticals. However, in the horizontal wells, 74% of the successful ones were the heel shut-offs. WSO activities are found to have a success rate of 100% if the activity is implemented within the first year of the start of high water cut. Moreover, wells with WSO implementation within the first three years of observing high water-cut have a success rate of 65%. Noticeably, the success rate decreased dramatically with time, with wells having high water-cut for seven years and up to eleven years to the time of WSO implementation. These wells show success rates of 50% and 33% for seven and eleven years respectively.\u0000 A numerical sector model and well model were created to explain these findings. During oil production because of a localized decrease in pressure, the water-oil interface may rise up and deform into a conical shape near the well. This phenomenon is known as ‘water coning’. At the time of water breakthrough, the cone is observed to be narrower than more advanced stages when the water cut has risen to higher levels. At these times, the cone has broadened and, depending on spacing between adjacent wells, has lifted the overall level of the oil/water interface, decreasing the distance between the wellbore and the water. As a result, water shutoff becomes less effective with time.\u0000 It is recommended to start WSO activities on wells within the first three years of high water-cut indications. In case there is no PLT or other data, heel shutoff for the horizontal wells have a better success rate.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"47 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74697003","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}
P. Dell’Aversana, R. Servodio, E. Rizzo, P. Cappuccio, C. Carniani
Real-time mapping reservoir fluids distribution during hydrocarbon production, or during injection operation, represents a crucial issue and a big challenge at the same time. In this article, we present a new approach based on single-well and cross-well electric measurements. We use electrodes permanently installed on the well casing and electrically insulated from it. We tested our approach through a two-steps workflow. In the first step, we performed forward and inverse modelling on realistic production scenarios. In the second step, we acquired, processed and inverted real data acquired in laboratory, where we tested small-scale scenarios of hydrocarbon production. We acquired and inverted DC (Direct Current) data. Our objective was to reconstruct the variations of the 3D distribution of electric resistivity during the various phases of oil production. The retrieved models reproduced properly the experimental movements of fluids observed in our lab measurements. Finally, modelling and inversion of both synthetic and real data confirm that cross-hole DC method allows mapping reservoir fluid variations even in case of predominant metallic components of the well completion.
{"title":"Real-Time Hydrocarbon Mapping by Time-Lapse Borehole Electric Tomography","authors":"P. Dell’Aversana, R. Servodio, E. Rizzo, P. Cappuccio, C. Carniani","doi":"10.2118/193183-MS","DOIUrl":"https://doi.org/10.2118/193183-MS","url":null,"abstract":"\u0000 Real-time mapping reservoir fluids distribution during hydrocarbon production, or during injection operation, represents a crucial issue and a big challenge at the same time. In this article, we present a new approach based on single-well and cross-well electric measurements. We use electrodes permanently installed on the well casing and electrically insulated from it. We tested our approach through a two-steps workflow. In the first step, we performed forward and inverse modelling on realistic production scenarios. In the second step, we acquired, processed and inverted real data acquired in laboratory, where we tested small-scale scenarios of hydrocarbon production. We acquired and inverted DC (Direct Current) data. Our objective was to reconstruct the variations of the 3D distribution of electric resistivity during the various phases of oil production. The retrieved models reproduced properly the experimental movements of fluids observed in our lab measurements. Finally, modelling and inversion of both synthetic and real data confirm that cross-hole DC method allows mapping reservoir fluid variations even in case of predominant metallic components of the well completion.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75401228","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}
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}
M. A. Marzouqi, L. Saputelli, M. Abdou, R. Mohan, S. Pandian, Maryam Al Hammadi, Muhammad Navaid Khan, J. Cumming, J. Pires, Alvaro Escorcia
The objective of this work is to enable the collaboration of multiple disciplines in the performance reviews of reservoirs while establishing a culture of variance reduction and sustainable consistency in results delivery. This effort focuses on the performance management reviews of very large carbonate reservoirs where the number of wells and producing zones overwhelm engineers and organizations with data volume and complexity due to areal and vertical heterogeneity. A novel Reservoir Performance Review (RPR) solution has been implemented across various offshore reservoirs units. RPR initiates all asset activities during reservoir performance reviews and allows the tracking of actions over the life of the reservoir. RPR leverages data analytics to automatically compute reservoir health key performance indicators that allow prioritization of the technical work, extract and transform data from multiple data sources, deliver performance dashboards with diagnostic plot standardized across all assets and users providing an archive of information and knowledge from past reservoir performance reviews. RPR leverages business process management and integrated visualization to assist in the identification and recording of opportunities, risks and actions, while providing control and management of the business processes. The solution offers an innovative way to collaboratively gather, validate, analyze reservoir performance across the asset on a sustainable and cost-efficient manner while addressing more formal approval processes in order to garner approval or authorization for action. Some of the realized benefits include ensuring effectiveness in the execution of reservoir management, monitor variance between actual performance and expectation during the execution of projects; and ensure production sustainability and mitigate shortfalls proactively. RPR enabled the achievement of a consistent approach across all assets for all reservoir performance review processes, while improving efficiency through automation of data gathering and presentation and the identification of all underperforming reservoir, sectors and fields. Reservoir management excellence is achieved by delivering immediate value on the opportunities identified during performance reviews which ensure short term profitability while preserving long term goals. Typically, operators are satisfied by meeting targets within certain tolerance. RPR ensures that performance excellence is achieved by considering all technical and business aspects.
{"title":"Automated Multidisciplinary Collaboration in Integrated Reservoir Management IRM through Business Process Management BPM","authors":"M. A. Marzouqi, L. Saputelli, M. Abdou, R. Mohan, S. Pandian, Maryam Al Hammadi, Muhammad Navaid Khan, J. Cumming, J. Pires, Alvaro Escorcia","doi":"10.2118/193012-MS","DOIUrl":"https://doi.org/10.2118/193012-MS","url":null,"abstract":"\u0000 The objective of this work is to enable the collaboration of multiple disciplines in the performance reviews of reservoirs while establishing a culture of variance reduction and sustainable consistency in results delivery. This effort focuses on the performance management reviews of very large carbonate reservoirs where the number of wells and producing zones overwhelm engineers and organizations with data volume and complexity due to areal and vertical heterogeneity.\u0000 A novel Reservoir Performance Review (RPR) solution has been implemented across various offshore reservoirs units. RPR initiates all asset activities during reservoir performance reviews and allows the tracking of actions over the life of the reservoir.\u0000 RPR leverages data analytics to automatically compute reservoir health key performance indicators that allow prioritization of the technical work, extract and transform data from multiple data sources, deliver performance dashboards with diagnostic plot standardized across all assets and users providing an archive of information and knowledge from past reservoir performance reviews.\u0000 RPR leverages business process management and integrated visualization to assist in the identification and recording of opportunities, risks and actions, while providing control and management of the business processes.\u0000 The solution offers an innovative way to collaboratively gather, validate, analyze reservoir performance across the asset on a sustainable and cost-efficient manner while addressing more formal approval processes in order to garner approval or authorization for action. Some of the realized benefits include ensuring effectiveness in the execution of reservoir management, monitor variance between actual performance and expectation during the execution of projects; and ensure production sustainability and mitigate shortfalls proactively. RPR enabled the achievement of a consistent approach across all assets for all reservoir performance review processes, while improving efficiency through automation of data gathering and presentation and the identification of all underperforming reservoir, sectors and fields.\u0000 Reservoir management excellence is achieved by delivering immediate value on the opportunities identified during performance reviews which ensure short term profitability while preserving long term goals. Typically, operators are satisfied by meeting targets within certain tolerance. RPR ensures that performance excellence is achieved by considering all technical and business aspects.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89075130","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}
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}
The Objectives of this technical paper are: To share ADNOC Group experience in creating and implementing a Code Of Practice (COP) for Operating IntegrityTo demonstrate the imperative and business case for Operating IntegrityTo present the challenges and critical success factors for successful implementation The scope is all operational production and manufacturing sites across ADNOC upstream and downstream operating companies. Operating Integrity is a strategic focus area within the ADNOC Operational Excellence program. It is an imperative within the Oil and Gas industry in order to Ensure Safe Production and optimise availability. Several catastrophic process safety incidents within the industry have demonstrated that poor risk management and a lack of good operating practices by site operators can lead to massive business and human costs. Operating Integrity addresses the root causes of major industry accidents such as: poor control of safeguarding overrides; poor Alarm management; ill-defined operating envelopes; lack of effective shift handovers; PTW control failures; not following operating procedures; lack of operator competency. Traditionally, these topics have received less focus than technical and design integrity, but should be considered equally important. Typically Operating Integrity is centered around human factors and therefore has its specific implementation challenges. ADNOC has collaborated with experts in each operating company to write a COP for Operating Integrity by adopting good practice from the OPCO's and benchmarking these practices with the wider industry (LEAN approach). This in-house collaboration has achieved strong ownership and the fast track development of a fit for purpose COP, whilst enabling the creation of a tailored change management plan to ensure the effective roll-out, communication and compliance with the COP at all operating sites. The paper will further elaborate on the main elements contained in the COP, which can be summarized as: Competent people in all HSE critical roles all the time (even when others are on leave or at training)Operating all our facilities within up to date operating envelopesManaging risk resulting from any deviations from design or abnormal operating conditionsRationalising and knowing how to react to alarmsUsing the Permit To Work systems effectivelyClear, consistent and effective daily communications and shift handoversAccessible and up to date procedures which are followed consistentlyAccessible and up to date critical drawings and documentsReal time visibility of over-rides and inhibits and a procedure regarding how to respond to them The paper will elaborate on the Critical success factors for ADNOC implementation of the COP, which include: Leadership CommitmentEffective communication about Operating Integrity to senior leaders, middle management and site operations teams (the latter via mandatory e-learning packages)Establishing a change management plan and governing
{"title":"Operating Integrity - The ADNOC Journey to Ensure Safe Production","authors":"Stephen Brown, R. Qureshi, J. Zijlstra","doi":"10.2118/193020-MS","DOIUrl":"https://doi.org/10.2118/193020-MS","url":null,"abstract":"\u0000 The Objectives of this technical paper are: To share ADNOC Group experience in creating and implementing a Code Of Practice (COP) for Operating IntegrityTo demonstrate the imperative and business case for Operating IntegrityTo present the challenges and critical success factors for successful implementation\u0000 The scope is all operational production and manufacturing sites across ADNOC upstream and downstream operating companies.\u0000 Operating Integrity is a strategic focus area within the ADNOC Operational Excellence program. It is an imperative within the Oil and Gas industry in order to Ensure Safe Production and optimise availability. Several catastrophic process safety incidents within the industry have demonstrated that poor risk management and a lack of good operating practices by site operators can lead to massive business and human costs. Operating Integrity addresses the root causes of major industry accidents such as: poor control of safeguarding overrides; poor Alarm management; ill-defined operating envelopes; lack of effective shift handovers; PTW control failures; not following operating procedures; lack of operator competency. Traditionally, these topics have received less focus than technical and design integrity, but should be considered equally important. Typically Operating Integrity is centered around human factors and therefore has its specific implementation challenges.\u0000 ADNOC has collaborated with experts in each operating company to write a COP for Operating Integrity by adopting good practice from the OPCO's and benchmarking these practices with the wider industry (LEAN approach). This in-house collaboration has achieved strong ownership and the fast track development of a fit for purpose COP, whilst enabling the creation of a tailored change management plan to ensure the effective roll-out, communication and compliance with the COP at all operating sites. The paper will further elaborate on the main elements contained in the COP, which can be summarized as: Competent people in all HSE critical roles all the time (even when others are on leave or at training)Operating all our facilities within up to date operating envelopesManaging risk resulting from any deviations from design or abnormal operating conditionsRationalising and knowing how to react to alarmsUsing the Permit To Work systems effectivelyClear, consistent and effective daily communications and shift handoversAccessible and up to date procedures which are followed consistentlyAccessible and up to date critical drawings and documentsReal time visibility of over-rides and inhibits and a procedure regarding how to respond to them\u0000 The paper will elaborate on the Critical success factors for ADNOC implementation of the COP, which include: Leadership CommitmentEffective communication about Operating Integrity to senior leaders, middle management and site operations teams (the latter via mandatory e-learning packages)Establishing a change management plan and governing ","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"63 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89198646","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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