E. BinAbadat, H. Bu-Hindi, C. Lehmann, Atul Kumar, H. Al-Harbi, A. Al-Ali, Adel Al Katheeri
In this study, core and log data were integrated to identify intervals which are rich in stromatoporoids in an Upper Jurassic carbonate reservoir of an offshore green field Abu Dhabi. The main objective of this study was to recognize and stromatoporoids floatstones/rudstones in core, and develop criteria and workflow to identify them in uncored wells using borehole images. The following workflow was used during this study: i) Identification of the stromatoporoid feature in pilot wells with core and borehole images, ii) Investigate the properties and architecture of stromatoporoid bodies, iii) Integrate the same scale of core observations with borehole images and conventional log data (gamma ray, neutron porosity and bulk density logs) to identify stromatoporoid-rich layers, iv) Performing a blind test on a well by using the criteria developed from previous steps to identify "stromatoporoid accumulations" on a borehole image, and validate it with core observations. In the reservoir under investgation, stromatoporoid floatstones/rudstones intervals were identified and recognized both on core and borehole image in the pilot wells. These distinct reservoir bodies of stromatoporoids commonly occur in upper part of the reservoir and can reach to a thickness of around 20ft. The distribution and thickness of stromatoporoid bodies as well as growth forms (massive versus branching) were recognized on core and borehole images. The accumulations varied between massive beds of containing large pieces of stromatoporoids and grainstone beds rich in stromatoporoid debris. The massive beds of stromatoporoid accumulations are well developed in the northern part of the field. These layers can enhance the reservoir quality because of their distinct vuggy porosity and permeability that can reach up to several hundred of milidarcies (mD). Therefore, it is important to capture stromatoporoid layers both vertically and laterally in the static and dynamic model. Integrating borehole image data with core data and developing a workflow to identify stromatoporoid intervals in uncored wells is crucial to our subsurface understanding and will help to understand reservoir performance. Integration of image log data which is calibrated to core and log data proved to be critical in generating reservoir facies maps and correlations, which were integrated into a sequence stratigraphic framework as well. The results were used in the static model in distribution of high permeability layers related to the distribution of stromatoporoids.
{"title":"A Workflow to Integrate Core and Image Logs in Order to Enhance the Characterization of Subsurface Facies on Carbonate Reservoirs, Offshore Abu Dhabi","authors":"E. BinAbadat, H. Bu-Hindi, C. Lehmann, Atul Kumar, H. Al-Harbi, A. Al-Ali, Adel Al Katheeri","doi":"10.2118/193192-MS","DOIUrl":"https://doi.org/10.2118/193192-MS","url":null,"abstract":"\u0000 In this study, core and log data were integrated to identify intervals which are rich in stromatoporoids in an Upper Jurassic carbonate reservoir of an offshore green field Abu Dhabi. The main objective of this study was to recognize and stromatoporoids floatstones/rudstones in core, and develop criteria and workflow to identify them in uncored wells using borehole images.\u0000 The following workflow was used during this study: i) Identification of the stromatoporoid feature in pilot wells with core and borehole images, ii) Investigate the properties and architecture of stromatoporoid bodies, iii) Integrate the same scale of core observations with borehole images and conventional log data (gamma ray, neutron porosity and bulk density logs) to identify stromatoporoid-rich layers, iv) Performing a blind test on a well by using the criteria developed from previous steps to identify \"stromatoporoid accumulations\" on a borehole image, and validate it with core observations.\u0000 In the reservoir under investgation, stromatoporoid floatstones/rudstones intervals were identified and recognized both on core and borehole image in the pilot wells. These distinct reservoir bodies of stromatoporoids commonly occur in upper part of the reservoir and can reach to a thickness of around 20ft. The distribution and thickness of stromatoporoid bodies as well as growth forms (massive versus branching) were recognized on core and borehole images. The accumulations varied between massive beds of containing large pieces of stromatoporoids and grainstone beds rich in stromatoporoid debris. The massive beds of stromatoporoid accumulations are well developed in the northern part of the field. These layers can enhance the reservoir quality because of their distinct vuggy porosity and permeability that can reach up to several hundred of milidarcies (mD). Therefore, it is important to capture stromatoporoid layers both vertically and laterally in the static and dynamic model. Integrating borehole image data with core data and developing a workflow to identify stromatoporoid intervals in uncored wells is crucial to our subsurface understanding and will help to understand reservoir performance.\u0000 Integration of image log data which is calibrated to core and log data proved to be critical in generating reservoir facies maps and correlations, which were integrated into a sequence stratigraphic framework as well. The results were used in the static model in distribution of high permeability layers related to the distribution of stromatoporoids.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90370949","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}
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}
A. Ali, Sangseok Park, Muhammad Mukhtar, K. Ghorayeb, Mohamad Alkhatib, Aditiya Ojha, Abdur Rahman Shah, J. Ortiz
Early assessment of enhanced oil recovery (EOR) potential in fields that are at early development stages is becoming more common in the oil industry, ensuring that investment decisions are consistent with the EOR deployment once the field reaches maturity. Well, facilities and monitoring design maybe influenced to accommodate the EOR implementation, thus reducing Capex and mitigating project exposure. Challenges arise, as expected, due to the limited information, particularly when the field has not yet been under production and dynamic information of connectivity, compartmentalization and reservoir extend is scarce. This paper describes the screening analysis performed on an onshore marginal green field in the UAE with four drilled wells and no production history with water injection considered on the approved development plan. The comprehensive screening workflow resulted on a narrow list of potential applicable EOR methods and their corresponding benefits allowing the operator to tailor development activities for early EOR de-risking and accelerated field deployment. A multi-dimensional approach was adopted using a combination of numerical, analytical methods and past EOR experience, to shortlist and rank the most attractive EOR development options, robustness of the selection (and ranking) was tested under the key reservoir uncertainties. WAG was identified as one of the better suited EOR processes (complemented the planned waterflood) along with miscible CO2 injection (with possible WAG applications).
{"title":"Robust EOR Screening Workflow for a Carbonate Green Field: A Case Study","authors":"A. Ali, Sangseok Park, Muhammad Mukhtar, K. Ghorayeb, Mohamad Alkhatib, Aditiya Ojha, Abdur Rahman Shah, J. Ortiz","doi":"10.2118/192700-MS","DOIUrl":"https://doi.org/10.2118/192700-MS","url":null,"abstract":"\u0000 Early assessment of enhanced oil recovery (EOR) potential in fields that are at early development stages is becoming more common in the oil industry, ensuring that investment decisions are consistent with the EOR deployment once the field reaches maturity. Well, facilities and monitoring design maybe influenced to accommodate the EOR implementation, thus reducing Capex and mitigating project exposure. Challenges arise, as expected, due to the limited information, particularly when the field has not yet been under production and dynamic information of connectivity, compartmentalization and reservoir extend is scarce.\u0000 This paper describes the screening analysis performed on an onshore marginal green field in the UAE with four drilled wells and no production history with water injection considered on the approved development plan. The comprehensive screening workflow resulted on a narrow list of potential applicable EOR methods and their corresponding benefits allowing the operator to tailor development activities for early EOR de-risking and accelerated field deployment. A multi-dimensional approach was adopted using a combination of numerical, analytical methods and past EOR experience, to shortlist and rank the most attractive EOR development options, robustness of the selection (and ranking) was tested under the key reservoir uncertainties.\u0000 WAG was identified as one of the better suited EOR processes (complemented the planned waterflood) along with miscible CO2 injection (with possible WAG applications).","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"82 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87359550","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}
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}
Salamat Gumarov, S. Benelkadi, Eduardo Bianco, S. Woolf, Chris M. Hardy, Hisataka Ido, Manabu Tanaka, Naohiro Tominaga, K. Yahata, Takeru Okuzawa
Management of drilling wastes presents major challenges during drilling operations in environmentally protected areas. An Abu Dhabi offshore field development project selected cuttings reinjection (CRI) services as an appropriate solution for waste management. Although CRI is a proven technology in the region, fracturing injection always inherits its own containment-related risks. To prevent all possible failures that were experienced earlier in the industry globally, a novel real-time monitoring and analysis of fracturing injections data was introduced. A comprehensive front-end engineering design (FEED) study was performed to evaluate the feasibility of CRI techniques by selecting a suitable injection formation and designing a CRI-dedicated well, surface facilities, slurry testing, and appropriate operations execution plan. The CRI well was drilled and completed to accommodate waste volumes. An assurance program based on industry best practices was used to support zero solids settling, fracture, or perforation plugging. To achieve on-time intervention, the first real-time CRI data transfer through a satellite-based network to a support center staffed by global experts in Abu Dhabi was deployed to analyze fracture injection and shut-in pressure responses for early identification of possible risks and to map the fracture waste domain. The project has been operated successfully since its inception with more than 300,000 bbl of drilled cuttings and drilling waste fluids injected since July 2016. No injectivity issues were experienced during drilling waste fluids injection. Several on-time interventions had been made to prevent well plugging and to maintain surface injection pressures within normal ranges. Real-time data streaming has made a step-change improvement in the data delivery process, monitoring, and fracture pressure analysis. It creates a direct link between the wellsite and worldwide multidisciplinary technical expertise centralized in Abu Dhabi and provides visualization capability at any time and to any where to all personnel involved in the project. This step change in monitoring CRI operations provides an acquisition-to-answer" integrated solution, mitigates the injection risks, and enhances the intrinsic value of CRI services. The paper shares the experience of implementing the novel real-time CRI subsurface injection assurance program dedicated for cuttings reinjection operations. Real-time support from multidisciplinary experts provides live injection monitoring and fracture waste domain mapping for highly complex and risk-prone subsurface injection environments with stringent regulations
{"title":"First Implementation of Real-Time Subsurface Monitoring for Cuttings Reinjection Offshore Abu Dhabi","authors":"Salamat Gumarov, S. Benelkadi, Eduardo Bianco, S. Woolf, Chris M. Hardy, Hisataka Ido, Manabu Tanaka, Naohiro Tominaga, K. Yahata, Takeru Okuzawa","doi":"10.2118/192884-ms","DOIUrl":"https://doi.org/10.2118/192884-ms","url":null,"abstract":"\u0000 Management of drilling wastes presents major challenges during drilling operations in environmentally protected areas. An Abu Dhabi offshore field development project selected cuttings reinjection (CRI) services as an appropriate solution for waste management.\u0000 Although CRI is a proven technology in the region, fracturing injection always inherits its own containment-related risks. To prevent all possible failures that were experienced earlier in the industry globally, a novel real-time monitoring and analysis of fracturing injections data was introduced.\u0000 A comprehensive front-end engineering design (FEED) study was performed to evaluate the feasibility of CRI techniques by selecting a suitable injection formation and designing a CRI-dedicated well, surface facilities, slurry testing, and appropriate operations execution plan.\u0000 The CRI well was drilled and completed to accommodate waste volumes. An assurance program based on industry best practices was used to support zero solids settling, fracture, or perforation plugging.\u0000 To achieve on-time intervention, the first real-time CRI data transfer through a satellite-based network to a support center staffed by global experts in Abu Dhabi was deployed to analyze fracture injection and shut-in pressure responses for early identification of possible risks and to map the fracture waste domain.\u0000 The project has been operated successfully since its inception with more than 300,000 bbl of drilled cuttings and drilling waste fluids injected since July 2016. No injectivity issues were experienced during drilling waste fluids injection. Several on-time interventions had been made to prevent well plugging and to maintain surface injection pressures within normal ranges.\u0000 Real-time data streaming has made a step-change improvement in the data delivery process, monitoring, and fracture pressure analysis. It creates a direct link between the wellsite and worldwide multidisciplinary technical expertise centralized in Abu Dhabi and provides visualization capability at any time and to any where to all personnel involved in the project.\u0000 This step change in monitoring CRI operations provides an acquisition-to-answer\" integrated solution, mitigates the injection risks, and enhances the intrinsic value of CRI services.\u0000 The paper shares the experience of implementing the novel real-time CRI subsurface injection assurance program dedicated for cuttings reinjection operations. Real-time support from multidisciplinary experts provides live injection monitoring and fracture waste domain mapping for highly complex and risk-prone subsurface injection environments with stringent regulations","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86901575","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}
C. Temizel, A. Abdullayev, Rachit Kedia, S. Chhabra
One method of reducing the recognized threat of global warming is using continued sequestration of anthropogenic "greenhouse gases," such as carbon dioxide (CO2). Sedimentary basins are present globally and, because of the omnipresent nature of deep, regional-scale aquifers within them, they can be considered as potential sites for disposal and sequestration of CO2. Successful implementation requires identifying and considering fundamental concepts to help ensure that CO2 is stored in the aquifers effectively. The ideal scenario involves migrating CO2 from injection wells to remote storage sites using the aquifer, helping ensure its isolation from the atmosphere for a considerable length of time. In addition to the scientific and technical aspects of sequestration research, the practicality of the concept should be considered, including evaluating the maximum possible volume of CO2 that can be stored at global and regional levels as well as the safety and economic feasibility of the process. This study discusses examples to help provide an in-depth, practical understanding of this concept. The study combines a full-physics commercial simulator with an effective uncertainty and optimization tool. The sequestration phenomenon is then modeled to investigate the significance and effect of the essential parameters on well performance while also considering thermal and geochemical effects. The process assesses the injection of CO2 containing tracers for 25 years, followed by shutting in the injectors and modeling the status of CO2 for the next 225 years. While CO2 is injected into an aquifer, the molecular diffusion of CO2 in water is modeled. The modeling of the thermal effects attributable to the injection of CO2 is important because the chemical equilibrium constants have a functional thermal dependency. For reservoir management, the evaluation and effective management of uncertainties are as important as managing the well-level parameters. For this study, essential reservoir and well parameters are identified, and sensitivity and optimization processes are performed on them; the tornado charts in this paper illustrate the significance and effect of each parameter. Thermal and geochemical effects are shown to play vital roles in the sequestration process. This study outlines the significance of essential parameters associated with the overall success of the CO2 sequestration in aquifers using in-depth uncertainty and optimization analysis, and it considers the influence of thermal and geochemical effects.
{"title":"CO2 Sequestration Optimization in Aquifers While Considering Thermal and Geochemical Effects","authors":"C. Temizel, A. Abdullayev, Rachit Kedia, S. Chhabra","doi":"10.2118/192683-MS","DOIUrl":"https://doi.org/10.2118/192683-MS","url":null,"abstract":"\u0000 One method of reducing the recognized threat of global warming is using continued sequestration of anthropogenic \"greenhouse gases,\" such as carbon dioxide (CO2). Sedimentary basins are present globally and, because of the omnipresent nature of deep, regional-scale aquifers within them, they can be considered as potential sites for disposal and sequestration of CO2. Successful implementation requires identifying and considering fundamental concepts to help ensure that CO2 is stored in the aquifers effectively. The ideal scenario involves migrating CO2 from injection wells to remote storage sites using the aquifer, helping ensure its isolation from the atmosphere for a considerable length of time. In addition to the scientific and technical aspects of sequestration research, the practicality of the concept should be considered, including evaluating the maximum possible volume of CO2 that can be stored at global and regional levels as well as the safety and economic feasibility of the process. This study discusses examples to help provide an in-depth, practical understanding of this concept.\u0000 The study combines a full-physics commercial simulator with an effective uncertainty and optimization tool. The sequestration phenomenon is then modeled to investigate the significance and effect of the essential parameters on well performance while also considering thermal and geochemical effects. The process assesses the injection of CO2 containing tracers for 25 years, followed by shutting in the injectors and modeling the status of CO2 for the next 225 years. While CO2 is injected into an aquifer, the molecular diffusion of CO2 in water is modeled. The modeling of the thermal effects attributable to the injection of CO2 is important because the chemical equilibrium constants have a functional thermal dependency.\u0000 For reservoir management, the evaluation and effective management of uncertainties are as important as managing the well-level parameters. For this study, essential reservoir and well parameters are identified, and sensitivity and optimization processes are performed on them; the tornado charts in this paper illustrate the significance and effect of each parameter. Thermal and geochemical effects are shown to play vital roles in the sequestration process.\u0000 This study outlines the significance of essential parameters associated with the overall success of the CO2 sequestration in aquifers using in-depth uncertainty and optimization analysis, and it considers the influence of thermal and geochemical effects.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"113 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86985356","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}
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}
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