In this work, we introduce a spectroscopy system based on an electronic source that can radiate terahertz frequency combs to perform broadband spectroscopy of trace gases. A single-chip source provides us with a highly compact and cost-effective system in comparison with a laser-based source, and a faster response time in comparison with chemical sensors. We have performed THz gas spectroscopy using three different gases, H2S, NH3, and H2O. These measurements have been performed at 575, 736, and 754 GHz.
{"title":"Precision Gas Sensing Based on THz Spectroscopy","authors":"M. Assefzadeh, Babak Jamali, A. Babakhani","doi":"10.2118/192899-MS","DOIUrl":"https://doi.org/10.2118/192899-MS","url":null,"abstract":"\u0000 In this work, we introduce a spectroscopy system based on an electronic source that can radiate terahertz frequency combs to perform broadband spectroscopy of trace gases. A single-chip source provides us with a highly compact and cost-effective system in comparison with a laser-based source, and a faster response time in comparison with chemical sensors. We have performed THz gas spectroscopy using three different gases, H2S, NH3, and H2O. These measurements have been performed at 575, 736, and 754 GHz.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87605397","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 process of differentiating between rock volumes based on petrophysical properties and geological indicators is commonly referred to as rock typing. A rock type can be identified by a given porosity – permeability (k-Phi) transform and Saturation Height Model (SHM) in petrophysical space. Rock typing is a useful method by which geological interpretations are combined with petrophysical measurements and translated into physical space for use in subsurface modelling. Efforts here involve utilizing k-Phi transforms as an input to SHM, thereby streamlining the rock typing process and allowing for compatibility with existing rock typing workflows. A fundamental part of building realistic subsurface models includes populating a geologic framework with petrophysical properties. From a petrophysical point of view, critical properties with significant impact on the modelling outcome (hydrocarbon volumes recoverable and producibility) are hydrocarbon saturation, permeability and relative permeability. Hydrocarbon saturation is an expression of the rock capillarity translated into a mathematical expression from capillary pressure measurements or well log saturations. Permeability is commonly predicted from porosity, via transform equations used to differentiate reservoir rocks of different quality. Previous work has shown that permeability and SHM used for subsurface modelling are generally consistent. This implies that the number of input parameters to the SHM can be reduced, which can be done by integrating permeability and saturation data (from logs and core measurements). The number of parameters used in the predictive SHM is reduced from six to four. Here, we propose to constrain the entry pressure (responsible for hydrocarbon entry height) by using routine core analysis data. This approach aiming to look at the plug and log scale has significant benefits when a SHM is derived from well log saturation data or when a limited range in properties is sampled by capillary pressure measurements. The workflow allows the use of other permeability sources (like Drill Stem Test if representative of matrix) as starting point in the process of building a SHM via a simplified Brooks-Corey function. The function can be looked at as a hybrid between the Leverett's J and Brooks-Corey function with entry pressure dependency on the permeability to porosity ratio higher than for Leverett's J (0.7 vs 0.5). The result of linking k-Phi transforms to saturation height modelling allows for compatibility with multiple rock typing approaches that utilize different sorts of parameters to define k-Phi, including Lucia's classic rock fabric numbers, a useful benchmark.
根据岩石物理性质和地质指标区分岩石体积的过程通常被称为岩石分型。岩石物理空间中给定的孔隙度-渗透率(k-Phi)变换和饱和高度模型(SHM)可以识别岩石类型。岩石分型是一种有用的方法，通过这种方法，地质解释与岩石物理测量相结合，并转化为用于地下建模的物理空间。这里的工作包括利用k-Phi变换作为SHM的输入，从而简化岩石分型过程，并允许与现有岩石分型工作流程兼容。建立真实的地下模型的一个基本部分包括用岩石物理性质填充地质框架。从岩石物理学的角度来看，对建模结果(油气可采体积和产能)有重大影响的关键属性是油气饱和度、渗透率和相对渗透率。油气饱和度是将岩石毛细作用转化为毛细压力测量或测井饱和度的数学表达式。渗透率通常由孔隙度预测，通过转换方程来区分不同质量的储层岩石。以前的工作表明，用于地下建模的渗透率和SHM通常是一致的。这意味着SHM输入参数的数量可以减少，这可以通过整合渗透率和饱和度数据(来自测井和岩心测量)来实现。在预测SHM中使用的参数数量从6个减少到4个。在这里，我们建议使用常规岩心分析数据来限制进入压力(负责油气进入高度)。当从测井饱和度数据中得出SHM，或者通过毛细管压力测量采样有限的属性范围时，这种旨在观察桥塞和测井尺度的方法具有显著的优势。该工作流程允许使用其他渗透率源(如钻杆测试，如果代表矩阵)作为通过简化的Brooks-Corey函数构建SHM过程的起点。该函数可以看作是Leverett的J函数和Brooks-Corey函数的混合体，其进入压力依赖于渗透率与孔隙度比高于Leverett的J函数(0.7 vs 0.5)。将k-Phi转换到饱和高度建模的结果允许与多种岩石类型方法兼容，这些方法使用不同类型的参数来定义k-Phi，包括Lucia的经典岩石结构数，这是一个有用的基准。
{"title":"A Method to Obtain a Permeability - Constrained and Consistent Saturation Height Model","authors":"I. Hulea","doi":"10.2118/193164-MS","DOIUrl":"https://doi.org/10.2118/193164-MS","url":null,"abstract":"\u0000 The process of differentiating between rock volumes based on petrophysical properties and geological indicators is commonly referred to as rock typing. A rock type can be identified by a given porosity – permeability (k-Phi) transform and Saturation Height Model (SHM) in petrophysical space. Rock typing is a useful method by which geological interpretations are combined with petrophysical measurements and translated into physical space for use in subsurface modelling. Efforts here involve utilizing k-Phi transforms as an input to SHM, thereby streamlining the rock typing process and allowing for compatibility with existing rock typing workflows.\u0000 A fundamental part of building realistic subsurface models includes populating a geologic framework with petrophysical properties. From a petrophysical point of view, critical properties with significant impact on the modelling outcome (hydrocarbon volumes recoverable and producibility) are hydrocarbon saturation, permeability and relative permeability. Hydrocarbon saturation is an expression of the rock capillarity translated into a mathematical expression from capillary pressure measurements or well log saturations. Permeability is commonly predicted from porosity, via transform equations used to differentiate reservoir rocks of different quality.\u0000 Previous work has shown that permeability and SHM used for subsurface modelling are generally consistent. This implies that the number of input parameters to the SHM can be reduced, which can be done by integrating permeability and saturation data (from logs and core measurements). The number of parameters used in the predictive SHM is reduced from six to four. Here, we propose to constrain the entry pressure (responsible for hydrocarbon entry height) by using routine core analysis data. This approach aiming to look at the plug and log scale has significant benefits when a SHM is derived from well log saturation data or when a limited range in properties is sampled by capillary pressure measurements. The workflow allows the use of other permeability sources (like Drill Stem Test if representative of matrix) as starting point in the process of building a SHM via a simplified Brooks-Corey function. The function can be looked at as a hybrid between the Leverett's J and Brooks-Corey function with entry pressure dependency on the permeability to porosity ratio higher than for Leverett's J (0.7 vs 0.5). The result of linking k-Phi transforms to saturation height modelling allows for compatibility with multiple rock typing approaches that utilize different sorts of parameters to define k-Phi, including Lucia's classic rock fabric numbers, a useful benchmark.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 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":"90291544","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}
To meet the regulations on the emission of toxic gases such as carbon monoxide (CO) and Hydrogen Sulfide (H2S) from the Sulphur Recovery Units (SRUs), a high amount of fuel gas is burnt in the incinerator to oxidize them that increases the sulfur production cost and CO2 emissions. This study investigates the major reactions that cause CO emissions and recommends possible solution to mitigate its formation in the SRU. The SRU simulations were conducted using a well validated and detailed reaction mechanism that captures the chemistry of CO and Sulfur species in the Claus furnace. The Claus reaction mechanism, containing 290 species and 1900 reversible reactions for the oxidation of H2S and the formation and destruction of COS, CO, CO2, hydrocarbons, and CS2 was used for reactor simulations, which was validated successfully using industrial plant data and the experimental data from lab-scale setups. The process parameters were varied to find the set of conditions that minimize CO production in the SRUs. The CO production in Claus furnace occurred through the high temperature decomposition of CO2 and CH4 present in the acid gas stream. The production of COS occurred from the reactions of CO with sulfur. The inlet temperatures of the feed gas streams (air and acid gas) were varied systematically to observe their effect on sulfur recovery and emissions of CO, SO2, COS, and aromatics. Upon decreasing the furnace temperature (by decreasing inlet air temperature) from 1105°C to 1050°C, CO emission from the SRU decreased by up to 60%, while sulfur recovery efficiency increased by 0.2%. However, the emission of aromatics (mainly benzene) increased by 3.5 ppm, while the more detrimental toluene, ethylbenzene and xylene were completely oxidized. Thus, maintaining an optimal feed temperature was found to minimize CO emissions from the SRUs, while maintaining high sulfur recovery. The simulation results predict the cost-effective solutions of minimizing CO and SO2 emissions from SRUs through the variation in process parameters that will help in reducing the consumption of fuel gas in the SRU incinerator.
{"title":"A Kinetic Simulation Study to Decrease Carbon Monoxide CO Emission from Sulfur Recovery Units SRU","authors":"S. Ibrahim, Ramees K. Rahman, A. Raj","doi":"10.2118/192771-MS","DOIUrl":"https://doi.org/10.2118/192771-MS","url":null,"abstract":"\u0000 To meet the regulations on the emission of toxic gases such as carbon monoxide (CO) and Hydrogen Sulfide (H2S) from the Sulphur Recovery Units (SRUs), a high amount of fuel gas is burnt in the incinerator to oxidize them that increases the sulfur production cost and CO2 emissions. This study investigates the major reactions that cause CO emissions and recommends possible solution to mitigate its formation in the SRU. The SRU simulations were conducted using a well validated and detailed reaction mechanism that captures the chemistry of CO and Sulfur species in the Claus furnace. The Claus reaction mechanism, containing 290 species and 1900 reversible reactions for the oxidation of H2S and the formation and destruction of COS, CO, CO2, hydrocarbons, and CS2 was used for reactor simulations, which was validated successfully using industrial plant data and the experimental data from lab-scale setups. The process parameters were varied to find the set of conditions that minimize CO production in the SRUs. The CO production in Claus furnace occurred through the high temperature decomposition of CO2 and CH4 present in the acid gas stream. The production of COS occurred from the reactions of CO with sulfur. The inlet temperatures of the feed gas streams (air and acid gas) were varied systematically to observe their effect on sulfur recovery and emissions of CO, SO2, COS, and aromatics. Upon decreasing the furnace temperature (by decreasing inlet air temperature) from 1105°C to 1050°C, CO emission from the SRU decreased by up to 60%, while sulfur recovery efficiency increased by 0.2%. However, the emission of aromatics (mainly benzene) increased by 3.5 ppm, while the more detrimental toluene, ethylbenzene and xylene were completely oxidized. Thus, maintaining an optimal feed temperature was found to minimize CO emissions from the SRUs, while maintaining high sulfur recovery. The simulation results predict the cost-effective solutions of minimizing CO and SO2 emissions from SRUs through the variation in process parameters that will help in reducing the consumption of fuel gas in the SRU incinerator.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"68 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89864791","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. G. Mayani, R. Rommetveit, S. I. Oedegaard, Morten Svendsen
Having a Digital Twin of the drilling well, pairing digital and physical data combined with predictive analytics and diagnostic messages, improves accuracy in planning and decision making of the drilling operation. It helps the industry to increase safety, improve efficiency and gain the best economic-value-based decision as well as reduce operational cost. Today advanced monitoring is normally done using real-time measurements, compare pre-simulation results with measurements, perform manual diagnostics and run new simulations when abnormalities are seen. All done manually by people. Drilling can move beyond advanced monitoring using Digital Twin's by implementing automatic ‘forward-looking’ and multiple ‘what-if’ simulation to give operations the optimal plan with focus on safety, risk reduction and improved performance. The Digital Twin examples in the current paper can do more advanced and complex automatic forecasting simulations, diagnostics, ‘forward-looking’ and ‘what-if’ simulation as well as predictive analytics in the wellbore in the 2D and 3D simulation view. By using the advanced models (Digital Twin), all relevant challenges and risks were identified during the drilling operations of one well under high pressure high temperature (HPHT) conditions. The stand pipe pressure (SPP), equivalent circulating density (ECD) and temperature behavior were studied during the drilling and circulation of this well. The Digital Twin was also used to evaluate possible losses during 9 7/8″ casing running and cementing with special focus on when casing was passing through the formations. In another well the Digital Twin triggered an early notification regarding high cuttings concentration during drilling 8 ½″ section. The flow rate was adjusted and helped to prevent sidetrack and pack-off due to losses. Morover during drilling 17 ½″ section in another case, large losses were prevented by comparing the modeled active pit calculation and measured tank volume. The Digital Twin enables advanced automatic forecasting simulation, self-diagnostics, automatic ‘forward-looking’, multiple ‘what-if’ simulation and predictive analytics to improve safety, reduce risk, increase drilling performance and reduce costs.
{"title":"Drilling Automated Realtime Monitoring Using Digital Twin","authors":"M. G. Mayani, R. Rommetveit, S. I. Oedegaard, Morten Svendsen","doi":"10.2118/192807-MS","DOIUrl":"https://doi.org/10.2118/192807-MS","url":null,"abstract":"\u0000 Having a Digital Twin of the drilling well, pairing digital and physical data combined with predictive analytics and diagnostic messages, improves accuracy in planning and decision making of the drilling operation. It helps the industry to increase safety, improve efficiency and gain the best economic-value-based decision as well as reduce operational cost. Today advanced monitoring is normally done using real-time measurements, compare pre-simulation results with measurements, perform manual diagnostics and run new simulations when abnormalities are seen. All done manually by people.\u0000 Drilling can move beyond advanced monitoring using Digital Twin's by implementing automatic ‘forward-looking’ and multiple ‘what-if’ simulation to give operations the optimal plan with focus on safety, risk reduction and improved performance.\u0000 The Digital Twin examples in the current paper can do more advanced and complex automatic forecasting simulations, diagnostics, ‘forward-looking’ and ‘what-if’ simulation as well as predictive analytics in the wellbore in the 2D and 3D simulation view.\u0000 By using the advanced models (Digital Twin), all relevant challenges and risks were identified during the drilling operations of one well under high pressure high temperature (HPHT) conditions. The stand pipe pressure (SPP), equivalent circulating density (ECD) and temperature behavior were studied during the drilling and circulation of this well. The Digital Twin was also used to evaluate possible losses during 9 7/8″ casing running and cementing with special focus on when casing was passing through the formations. In another well the Digital Twin triggered an early notification regarding high cuttings concentration during drilling 8 ½″ section. The flow rate was adjusted and helped to prevent sidetrack and pack-off due to losses.\u0000 Morover during drilling 17 ½″ section in another case, large losses were prevented by comparing the modeled active pit calculation and measured tank volume. The Digital Twin enables advanced automatic forecasting simulation, self-diagnostics, automatic ‘forward-looking’, multiple ‘what-if’ simulation and predictive analytics to improve safety, reduce risk, increase drilling performance and reduce costs.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83650248","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}
Dakhil Al-Enezi, Mohammad Al-Salamin, Sulaiman Sulaiman, Z. Muqaddas, Jasim Al-shelian, M. Fahmy, Ahmed Alrashoud, Ali Gholoum, Mubarak Almarshad, Ahmed S. Ibrahim, Ali Alotaibi, Shahad Sheer
It is a challenge to drill a highly deviated or horizontal hole in high permeable formations. High differential pressures may lead to several problems like tight holes, wellbore instability, differential sticking and mud loss while drilling across these permeable or fractured formations. It was always preferred to drill these wells with Oil base muds which showed some success. While operators always prefer the standard solution, which is casing isolation for problematic sections, challenges have increased due to continuously drilling in depleted reservoirs which leads to considerable nonproductive time. The other solution to overcome such problematic sections was to re-design a fluid system that would target drilling through serious of highly permeable sand and shale formations. The fluid system would primarily address shale inhibition along with effective bridging, minimizing pore pressure transmission and wellbore strengthen with increased hoop stress in the wellbore. Software modelling and permeability plugging tests were performed to evaluate the fluid behavior under downhole conditions and to predict the characteristics of induced micro fractures based on rock mechanics. Porosity, permeability and induced micro fractures were considered to optimize the bridging mechanism. It was identified that normal bridging solutions involving calcium carbonates and graphite material were not enough to address the pore pressure transmission problem. It was essential to include a micronized sealing deformable polymer along with normal bridging material was effective in plugging pore throats and minimizing fluid invasion. The deformable polymer component is able to re-shape itself to fit a broad range of pore throat sizes which was previously unattainable with conventional bridging technology which was confirmed by particle plugging tests. A one well was identified to be drilled in highly depleted reservoir at an inclination of almost 45 degrees. The section involving the highly depleted and permeable sand involved drilling highly stressed shale formations which requires high mud weight for their stability. This was the first attempt on a high-angle well with development drilling operations in Kuwait and was performed to facilitate the successful drilling of the reservoir. Drilling and logging were successfully performed along with logging and LWD runs with no recordable differential sticking or losses incidents. This paper also presents 2 successful applications in the same field with the application of proper bridging and utilization of deformable sealing polymer to address drilling problems through highly depleted and permeable formations while managing over balance of 3500 psi across them.
{"title":"Micronized Sealing Polymer Improves Wellbore Strengthening & Minimizes Differential Sticking Problems in Highly Depleted Formations","authors":"Dakhil Al-Enezi, Mohammad Al-Salamin, Sulaiman Sulaiman, Z. Muqaddas, Jasim Al-shelian, M. Fahmy, Ahmed Alrashoud, Ali Gholoum, Mubarak Almarshad, Ahmed S. Ibrahim, Ali Alotaibi, Shahad Sheer","doi":"10.2118/193345-MS","DOIUrl":"https://doi.org/10.2118/193345-MS","url":null,"abstract":"\u0000 It is a challenge to drill a highly deviated or horizontal hole in high permeable formations. High differential pressures may lead to several problems like tight holes, wellbore instability, differential sticking and mud loss while drilling across these permeable or fractured formations. It was always preferred to drill these wells with Oil base muds which showed some success. While operators always prefer the standard solution, which is casing isolation for problematic sections, challenges have increased due to continuously drilling in depleted reservoirs which leads to considerable nonproductive time.\u0000 The other solution to overcome such problematic sections was to re-design a fluid system that would target drilling through serious of highly permeable sand and shale formations. The fluid system would primarily address shale inhibition along with effective bridging, minimizing pore pressure transmission and wellbore strengthen with increased hoop stress in the wellbore. Software modelling and permeability plugging tests were performed to evaluate the fluid behavior under downhole conditions and to predict the characteristics of induced micro fractures based on rock mechanics. Porosity, permeability and induced micro fractures were considered to optimize the bridging mechanism. It was identified that normal bridging solutions involving calcium carbonates and graphite material were not enough to address the pore pressure transmission problem. It was essential to include a micronized sealing deformable polymer along with normal bridging material was effective in plugging pore throats and minimizing fluid invasion. The deformable polymer component is able to re-shape itself to fit a broad range of pore throat sizes which was previously unattainable with conventional bridging technology which was confirmed by particle plugging tests.\u0000 A one well was identified to be drilled in highly depleted reservoir at an inclination of almost 45 degrees. The section involving the highly depleted and permeable sand involved drilling highly stressed shale formations which requires high mud weight for their stability. This was the first attempt on a high-angle well with development drilling operations in Kuwait and was performed to facilitate the successful drilling of the reservoir. Drilling and logging were successfully performed along with logging and LWD runs with no recordable differential sticking or losses incidents.\u0000 This paper also presents 2 successful applications in the same field with the application of proper bridging and utilization of deformable sealing polymer to address drilling problems through highly depleted and permeable formations while managing over balance of 3500 psi across them.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"76 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86179716","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}
N. Ali, Haitham Abdulla, Ahmed Al Ameeri, M. Jacques, Ilhem Kouaiche
ADNOC LNG and TechnipFMC are reviewing options to reduce total sulphur in LNG, from a current realized specification of 4-9 mgS/Nm3, down to less than 1 mgS/Nm3. The requirement is to enhance the quality of the LNG product, and reduce environmental emissions. Several technologies were reviewed, including options to hydrolyze COS present in wet sweet gas, introduction of desulphurization beds downstream the dehydration units, and changing the type of molecular sieves. Those options were extensively reviewed, and found to be inadequate on their own. Therefore, solvent swap within the Acid Gas Removal Unit (AGRU) along with Molecular sieve upgrade was found to be the most viable option. Rigorous efforts were put in place to establish a robust roadmap that serves furnishing the correct basis, defining the required assessments and developing the intended approach and tools. This paper aims to present the overall methodology, approach and efforts undertaken to study the means to reduce sulphur species in LNG, in the present three LNG trains.
{"title":"Reduction of Sulfur Species in LNG to Ultra Low Levels","authors":"N. Ali, Haitham Abdulla, Ahmed Al Ameeri, M. Jacques, Ilhem Kouaiche","doi":"10.2118/192626-MS","DOIUrl":"https://doi.org/10.2118/192626-MS","url":null,"abstract":"\u0000 ADNOC LNG and TechnipFMC are reviewing options to reduce total sulphur in LNG, from a current realized specification of 4-9 mgS/Nm3, down to less than 1 mgS/Nm3. The requirement is to enhance the quality of the LNG product, and reduce environmental emissions.\u0000 Several technologies were reviewed, including options to hydrolyze COS present in wet sweet gas, introduction of desulphurization beds downstream the dehydration units, and changing the type of molecular sieves. Those options were extensively reviewed, and found to be inadequate on their own. Therefore, solvent swap within the Acid Gas Removal Unit (AGRU) along with Molecular sieve upgrade was found to be the most viable option.\u0000 Rigorous efforts were put in place to establish a robust roadmap that serves furnishing the correct basis, defining the required assessments and developing the intended approach and tools.\u0000 This paper aims to present the overall methodology, approach and efforts undertaken to study the means to reduce sulphur species in LNG, in the present three LNG trains.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86111447","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}
An engineered dual-purpose drilling and screen-running fluid was required to achieve optimum oil production with increased operational efficiency in a tight pressure window environment. The fluid needed to pose minimal formation damage risk while drilling and avoid completion damage through plugging of the standalone sand screen. This required a balance between bridging material content and particle size distribution (PSD), and a low fluid rheology to minimize the equivalent circulating density (ECD). The wide temperature profile and predicted restrictive narrow pressure margin in the well favored the use of a low ECD Non-Aqueous-Fluid (NAF). An organoclay-free NAF solution was selected. To reduce solids loading and ECD further, the fluid was designed with a brine phase that was high-density calcium bromide. Sized ground marble was selected to bridge the largest pore throats (42-μm) in the reservoir sand and still be screened quickly to avoid plugging of the 150-μm 6 5/8-in. standalone sand control production screens. Fluid optimization was achieved through rheology, stability, and formation-damage testing. The return permeability on cores/matched sandstone of >97%, indicated minimal formation damage risk when drilling and after production flowback/solids removal. In the field, the reservoir was drilled without major issue (i.e. no differential sticking, no down-hole losses) and the fluid quickly reached production screen test (PST) specifications prior to running screens. The sand screens were installed without issues. Although the sand section was significantly shorter than planned, the production from ~160 ft of net pay when the well was initially flowed produced as expected. After subsequent tie-in to the host floating production storage and offloading (FPSO) unit and upon choke opening, a gradual drop in production was observed. An acid job was performed via a subsea vessel-based operation and the planned production target exceeded the original clean-up well productivity.
{"title":"An Innovative Fluid Approach to Reservoir Drilling and Sand Screen Deployment: When Reality Meets Design and the Lessons Learned","authors":"Claire Webber, M. Langford","doi":"10.2118/193186-MS","DOIUrl":"https://doi.org/10.2118/193186-MS","url":null,"abstract":"\u0000 An engineered dual-purpose drilling and screen-running fluid was required to achieve optimum oil production with increased operational efficiency in a tight pressure window environment. The fluid needed to pose minimal formation damage risk while drilling and avoid completion damage through plugging of the standalone sand screen. This required a balance between bridging material content and particle size distribution (PSD), and a low fluid rheology to minimize the equivalent circulating density (ECD). The wide temperature profile and predicted restrictive narrow pressure margin in the well favored the use of a low ECD Non-Aqueous-Fluid (NAF). An organoclay-free NAF solution was selected. To reduce solids loading and ECD further, the fluid was designed with a brine phase that was high-density calcium bromide. Sized ground marble was selected to bridge the largest pore throats (42-μm) in the reservoir sand and still be screened quickly to avoid plugging of the 150-μm 6 5/8-in. standalone sand control production screens. Fluid optimization was achieved through rheology, stability, and formation-damage testing. The return permeability on cores/matched sandstone of >97%, indicated minimal formation damage risk when drilling and after production flowback/solids removal. In the field, the reservoir was drilled without major issue (i.e. no differential sticking, no down-hole losses) and the fluid quickly reached production screen test (PST) specifications prior to running screens. The sand screens were installed without issues. Although the sand section was significantly shorter than planned, the production from ~160 ft of net pay when the well was initially flowed produced as expected. After subsequent tie-in to the host floating production storage and offloading (FPSO) unit and upon choke opening, a gradual drop in production was observed. An acid job was performed via a subsea vessel-based operation and the planned production target exceeded the original clean-up well productivity.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84311910","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 recent major seismic events in South East Asia have led the Oil & Gas Companies to reevaluate the design of their offshore platforms with sometimes more stringent seismic conditions than original ones. The Yadana offshore platforms located in a high seismic activity area in the Andaman Sea, operated by TOTAL E&P MYANMAR, were part of this important work. DORIS Engineering and GDS have developed specific seismic analyses to validate the design under new conditions. This paper will present the different engineering challenges which were faced to revalidate the structural integrity of the different jacket type platforms under new seismic conditions. It will describe the methodology specifically developed for this project and how were identified and defined the necessary site modifications. These analyses were developed to assess more accurately the maximum relative displacements of jacket type platforms connected by bridges and to validate the stresses in foundation piles. It will also address the offshore works performed on the platforms with a maximization of SIMOPS works and limited shut down periods. Insufficiencies in the conventional design approach required to develop specific methods to validate the integrity of the jacket foundations and the platforms displacement (bridges). This paper will address, in particular, the design methodology used to verify the integrity of the jacket foundations and to define the required topsides and jacket reinforcements. A time domain approach, based on the "ASN" guidance used for nuclear facilities, was developed to verify the pile stresses and assess more accurately the maximum relative displacement of the platforms connected by bridges. The offshore works were afterwards performed in a timely and cost-effective manner. The detail engineering and the operation offshore had to include risky and unconventional operation such as bridges pot bearings replacement or piping modifications on bridges. SIMOPS works were maximized allowing the shutdown to be limited to the shortest duration. This paper presents the different engineering challenges which were faced to revalidate the design of existing platforms. It presents the specific methods which have been successfully developed by engineering to validate the design. This project is a good example of a "brownfield" project, from a challenging situation through development of a reliable and efficient engineering solution to successful completion of offshore works.
{"title":"Specific Analyses for the Reassessment of Existing Offshore Platforms Under New Seismic Conditions","authors":"Jérome Brocherie, F. Bounhoure, F. Barbier","doi":"10.2118/192817-MS","DOIUrl":"https://doi.org/10.2118/192817-MS","url":null,"abstract":"\u0000 The recent major seismic events in South East Asia have led the Oil & Gas Companies to reevaluate the design of their offshore platforms with sometimes more stringent seismic conditions than original ones. The Yadana offshore platforms located in a high seismic activity area in the Andaman Sea, operated by TOTAL E&P MYANMAR, were part of this important work. DORIS Engineering and GDS have developed specific seismic analyses to validate the design under new conditions.\u0000 This paper will present the different engineering challenges which were faced to revalidate the structural integrity of the different jacket type platforms under new seismic conditions. It will describe the methodology specifically developed for this project and how were identified and defined the necessary site modifications. These analyses were developed to assess more accurately the maximum relative displacements of jacket type platforms connected by bridges and to validate the stresses in foundation piles. It will also address the offshore works performed on the platforms with a maximization of SIMOPS works and limited shut down periods.\u0000 Insufficiencies in the conventional design approach required to develop specific methods to validate the integrity of the jacket foundations and the platforms displacement (bridges). This paper will address, in particular, the design methodology used to verify the integrity of the jacket foundations and to define the required topsides and jacket reinforcements. A time domain approach, based on the \"ASN\" guidance used for nuclear facilities, was developed to verify the pile stresses and assess more accurately the maximum relative displacement of the platforms connected by bridges. The offshore works were afterwards performed in a timely and cost-effective manner. The detail engineering and the operation offshore had to include risky and unconventional operation such as bridges pot bearings replacement or piping modifications on bridges. SIMOPS works were maximized allowing the shutdown to be limited to the shortest duration.\u0000 This paper presents the different engineering challenges which were faced to revalidate the design of existing platforms. It presents the specific methods which have been successfully developed by engineering to validate the design. This project is a good example of a \"brownfield\" project, from a challenging situation through development of a reliable and efficient engineering solution to successful completion of offshore works.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87992293","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}
F. Cailly, T. Al-Romani, C. Hubans, A. Lafram, A. Kaabi
This paper describes 4D interpretation results in a very challenging Middle East carbonate context. It consists of a 4D pilot (OBC/OBC) over a giant field divided into two phases. For Phase1 the monitor seismic survey has repeated the geometry of the base survey (parallel shooting) to get started in the best possible 4D conditions. For Phase2 the monitor seismic survey design is a modern source spread acquisition for wide azimuth objective. It is clearly different from the base survey design, and so starts with a worse 4D repeatibility. In this paper, we describe the challenges attached to both phases of this pilot and explain how in the end it has been successfully interpreted. A focused study is made on a particular 4D anomaly corresponding to an increase of impedance in the reservoir. This is interpreted as the water front movement (due to water injection) during the interval between base and monitor surveys. Petrophysically this is consistent, if water replaces oil in the reservoir then impedance increases. However, 4D interpretation can be ambiguous and other production phenomena can explain impedance increase, so the interpretation must be assessed carefully. This is done through calibration of the interpretation to well data (time evolution of the water cut). The final interpretation is robust. Other elements not described in the paper could have been added to consolidate the interpretation like the fact that interpreted 4D anomalies (and so water rise-up) stop vertically on a well known impermeable barrier (anhydrite level). Once the 4D signal is calibrated, unexpected phenomena (i.e. heterogeneities not predicted by the reservoir model) are highlighted as potentially providing added value to reservoir understanding. As a deliverable, 4D anomalies are interpreted as 3D geobodies and a water rise-up top surface is picked. This information will be key to position new wells and to update the reservoir model. Though 4D seismic techniques are very mature and widely illustrated in clastic reservoir environments, it is still rarely used operationally to monitor carbonate fields. This paper proves the concept that a reliable 4D signal can be extracted over such Middle-East carbonate reservoir.
{"title":"A Successful 4D Seismic Monitoring in Middle-East Carbonate Reservoir Context","authors":"F. Cailly, T. Al-Romani, C. Hubans, A. Lafram, A. Kaabi","doi":"10.2118/193063-MS","DOIUrl":"https://doi.org/10.2118/193063-MS","url":null,"abstract":"\u0000 This paper describes 4D interpretation results in a very challenging Middle East carbonate context.\u0000 It consists of a 4D pilot (OBC/OBC) over a giant field divided into two phases. For Phase1 the monitor seismic survey has repeated the geometry of the base survey (parallel shooting) to get started in the best possible 4D conditions. For Phase2 the monitor seismic survey design is a modern source spread acquisition for wide azimuth objective. It is clearly different from the base survey design, and so starts with a worse 4D repeatibility.\u0000 In this paper, we describe the challenges attached to both phases of this pilot and explain how in the end it has been successfully interpreted.\u0000 A focused study is made on a particular 4D anomaly corresponding to an increase of impedance in the reservoir. This is interpreted as the water front movement (due to water injection) during the interval between base and monitor surveys. Petrophysically this is consistent, if water replaces oil in the reservoir then impedance increases. However, 4D interpretation can be ambiguous and other production phenomena can explain impedance increase, so the interpretation must be assessed carefully. This is done through calibration of the interpretation to well data (time evolution of the water cut).\u0000 The final interpretation is robust. Other elements not described in the paper could have been added to consolidate the interpretation like the fact that interpreted 4D anomalies (and so water rise-up) stop vertically on a well known impermeable barrier (anhydrite level).\u0000 Once the 4D signal is calibrated, unexpected phenomena (i.e. heterogeneities not predicted by the reservoir model) are highlighted as potentially providing added value to reservoir understanding. As a deliverable, 4D anomalies are interpreted as 3D geobodies and a water rise-up top surface is picked. This information will be key to position new wells and to update the reservoir model.\u0000 Though 4D seismic techniques are very mature and widely illustrated in clastic reservoir environments, it is still rarely used operationally to monitor carbonate fields. This paper proves the concept that a reliable 4D signal can be extracted over such Middle-East carbonate reservoir.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"64 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90331999","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}
Zhengchun Liu, Robello Samuel, A. Gonzales, Yongfeng Kang
Tubular fatigue failures have been commonly reported in geothermal and heavy oil wells with cyclic steam injection operations. Recently, possible fatigue failures in casing connections during multistage fracturing operations have also been reported in the literature. These occurrences raised the question of whether casing fatigue is a real problem, even for shale plays. This paper describes fatigue modeling and analysis of the casing connections during fracturing operations to provide additional information about this issue. The varying casing temperature and temperature-dependent casing loads were obtained using numerical simulations of cyclic hydraulic fracturing operations, such as end of cementing → shut-in → plug and perforation → stimulation (stage 1) → shut-in → plug and perforation → stimulation (stage 2) etc. These simulations were accomplished using commercial software, including a thermal flow simulator and stress analyzer. The previously simulated casing loads were then used to calculate localized stress amplitude, strain amplitude, and maximum stress. Finally, the localized strain and stress values were used as input parameters of fatigue models to estimate the lifetime (cycles) of selected casing sections. The fatigue model was implemented in a computer program and integrated with the thermal flow and stress analysis commercial software, and a field case (shale oil/gas well) was studied with the integrated fatigue simulation. The predicted casing connection fatigue behavior closely correlates with failure field data, and the casing failure location was analyzed and explained in terms of environmental and cyclic stress/strain conditions. The corrosion fatigue appears important for the acidic environment during hydraulic fracturing. The field case study indicates that the fatigue analysis, coupled with numerical thermal-flow analysis and multistring stress analysis, can provide more insight into the failure of casing connections during fracturing operations. Consequently, it is valuable to include fatigue analysis during the wellbore tubular design when multistage fracturing and/or refracturing operations are involved.
{"title":"Analysis of Casing Fatigue Failure During Multistage Fracturing Operations","authors":"Zhengchun Liu, Robello Samuel, A. Gonzales, Yongfeng Kang","doi":"10.2118/193189-MS","DOIUrl":"https://doi.org/10.2118/193189-MS","url":null,"abstract":"\u0000 Tubular fatigue failures have been commonly reported in geothermal and heavy oil wells with cyclic steam injection operations. Recently, possible fatigue failures in casing connections during multistage fracturing operations have also been reported in the literature. These occurrences raised the question of whether casing fatigue is a real problem, even for shale plays. This paper describes fatigue modeling and analysis of the casing connections during fracturing operations to provide additional information about this issue.\u0000 The varying casing temperature and temperature-dependent casing loads were obtained using numerical simulations of cyclic hydraulic fracturing operations, such as end of cementing → shut-in → plug and perforation → stimulation (stage 1) → shut-in → plug and perforation → stimulation (stage 2) etc. These simulations were accomplished using commercial software, including a thermal flow simulator and stress analyzer. The previously simulated casing loads were then used to calculate localized stress amplitude, strain amplitude, and maximum stress. Finally, the localized strain and stress values were used as input parameters of fatigue models to estimate the lifetime (cycles) of selected casing sections.\u0000 The fatigue model was implemented in a computer program and integrated with the thermal flow and stress analysis commercial software, and a field case (shale oil/gas well) was studied with the integrated fatigue simulation. The predicted casing connection fatigue behavior closely correlates with failure field data, and the casing failure location was analyzed and explained in terms of environmental and cyclic stress/strain conditions. The corrosion fatigue appears important for the acidic environment during hydraulic fracturing. The field case study indicates that the fatigue analysis, coupled with numerical thermal-flow analysis and multistring stress analysis, can provide more insight into the failure of casing connections during fracturing operations. Consequently, it is valuable to include fatigue analysis during the wellbore tubular design when multistage fracturing and/or refracturing operations are involved.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88395353","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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