Danilo Colombo, D. C. G. Pedronette, I. R. Guilherme, J. Papa, L. C. Ribeiro, L. C. Afonso, João Gabriel Camacho Presotto, Gustavo José de Sousa
In well drilling activities, the execution of a sequence of operations defined in a well project is a central task. In order to provide proper monitoring, the operations executed during the drilling procedures are reported in Daily Drilling Reports (DDRs). Technologies capable of assisting the fulfillment of such reports represent valuable contributions. An approach using Machine Learning and Sequence Mining algorithms is proposed for predicting the next operation and classifying it based on textual descriptions. Nowadays, artificial intelligence (AI) applications play a key role in digital transformation process and is a very broad area, with various branches. Machine Learning techniques provide systems the ability to automatically learn and improve from experience without explicit instructions. Sequence Mining can be broadly defined as the task of finding statistical relevant patterns between samples modeled in a sequence. In our approach, the operations reported in DDRs are analyzed by Sequence Mining algorithms for predicting the next operation, whereas Machine Learning methods are used for automatically classifying the operations according to predefined ontologies based on textual descriptions. The proposed approach was experimentally validated using a real-world dataset composed of drilling reports with approximately 90K entries. Various sequence prediction algorithms are considered, more specifically: CPT+(Compact Prediction Tree+), DG (Dependency Graph), AKOM (All-k Order Markov), LZ78, PPM (Prediction by Partial Matching), and TDAG (Transitional Directed Acyclic Graph). For the classification tasks, approaches based on word embeddings and CRF (Conditional Random Fields) are exploited. Experimental results achieved high-accurate results, of 89% for the classification task. The promising results indicate that such strategies can be successfully exploited in the evaluated scenarios. Additionally, the positive results also encourage the investigation of its use in other oil and gas applications, since the reports organized through chronological order consists of a common scenario. The main contribution to the oil and gas industry consists of using artificial intelligence strategies in tasks associated with DDRs, saving human efforts and improving operational efficiency. Although the Sequence Mining and Machine Learning algorithms have been extensively used in different applications, the novelty of our work consists in the use of such approaches on the tasks of extracting useful information from the DDRs.
{"title":"Discovering Patterns within the Drilling Reports using Artificial Intelligence for Operation Monitoring","authors":"Danilo Colombo, D. C. G. Pedronette, I. R. Guilherme, J. Papa, L. C. Ribeiro, L. C. Afonso, João Gabriel Camacho Presotto, Gustavo José de Sousa","doi":"10.4043/29815-ms","DOIUrl":"https://doi.org/10.4043/29815-ms","url":null,"abstract":"\u0000 In well drilling activities, the execution of a sequence of operations defined in a well project is a central task. In order to provide proper monitoring, the operations executed during the drilling procedures are reported in Daily Drilling Reports (DDRs). Technologies capable of assisting the fulfillment of such reports represent valuable contributions. An approach using Machine Learning and Sequence Mining algorithms is proposed for predicting the next operation and classifying it based on textual descriptions.\u0000 Nowadays, artificial intelligence (AI) applications play a key role in digital transformation process and is a very broad area, with various branches. Machine Learning techniques provide systems the ability to automatically learn and improve from experience without explicit instructions. Sequence Mining can be broadly defined as the task of finding statistical relevant patterns between samples modeled in a sequence. In our approach, the operations reported in DDRs are analyzed by Sequence Mining algorithms for predicting the next operation, whereas Machine Learning methods are used for automatically classifying the operations according to predefined ontologies based on textual descriptions.\u0000 The proposed approach was experimentally validated using a real-world dataset composed of drilling reports with approximately 90K entries. Various sequence prediction algorithms are considered, more specifically: CPT+(Compact Prediction Tree+), DG (Dependency Graph), AKOM (All-k Order Markov), LZ78, PPM (Prediction by Partial Matching), and TDAG (Transitional Directed Acyclic Graph). For the classification tasks, approaches based on word embeddings and CRF (Conditional Random Fields) are exploited. Experimental results achieved high-accurate results, of 89% for the classification task. The promising results indicate that such strategies can be successfully exploited in the evaluated scenarios. Additionally, the positive results also encourage the investigation of its use in other oil and gas applications, since the reports organized through chronological order consists of a common scenario.\u0000 The main contribution to the oil and gas industry consists of using artificial intelligence strategies in tasks associated with DDRs, saving human efforts and improving operational efficiency. Although the Sequence Mining and Machine Learning algorithms have been extensively used in different applications, the novelty of our work consists in the use of such approaches on the tasks of extracting useful information from the DDRs.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"134 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77375938","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}
K. Beltrán-Jiménez, H. J. Skadsem, D. Gardner, S. Kragset, M. Souza
The cement between the casings and formation is a critical barrier element for ensuring zonal isolation. Shrinkage during curing and mechanical or thermal loads applied during production can compromise the cement and result in fluid migration paths such as micro-annuli. The fluid pressure inside the micro-annulus will cause elastic deformation of the channel walls. This deformation should be accounted for when developing methodologies for interpreting micro-annulus fluid leakage experiments and the application to real well conditions. Full-size test sections have been constructed with known cement defects and leakage properties to investigate barrier verification technologies. A micro-annulus test cell, instrumented with strain and pressure gauges, has been leakage tested. Leakage rates have been correlated to the micro-annulus size using a model coupling micro-annulus pressure to radial deformation of the cement and casing. The semi-analytical model and the predictions are compared to the experimental data. Within the regime of linear elasticity, the radial deformation of the cell wall is proportional to the pressure in the micro-annulus. During leakage testing, the pressure-driven radial deformation of the cell materials is coupled to the variation of the liquid friction pressure gradient along the axial length of the micro-annulus. The pressure gradient is greatest at the outlet of the micro-annulus. The models presented have been used to improve the interpretation of fluid flow during micro-annulus leakage experiments. An improved understanding of fluid leakage mechanisms through micro-annuli can be applied to field cases such as the interpretation and choice of treatment for sustained casing pressure build-up.
{"title":"Leakage Through Micro-Annulus Geometries Incorporating Pressure-Driven Elastic Deformation","authors":"K. Beltrán-Jiménez, H. J. Skadsem, D. Gardner, S. Kragset, M. Souza","doi":"10.4043/29718-ms","DOIUrl":"https://doi.org/10.4043/29718-ms","url":null,"abstract":"\u0000 The cement between the casings and formation is a critical barrier element for ensuring zonal isolation. Shrinkage during curing and mechanical or thermal loads applied during production can compromise the cement and result in fluid migration paths such as micro-annuli. The fluid pressure inside the micro-annulus will cause elastic deformation of the channel walls. This deformation should be accounted for when developing methodologies for interpreting micro-annulus fluid leakage experiments and the application to real well conditions. Full-size test sections have been constructed with known cement defects and leakage properties to investigate barrier verification technologies. A micro-annulus test cell, instrumented with strain and pressure gauges, has been leakage tested. Leakage rates have been correlated to the micro-annulus size using a model coupling micro-annulus pressure to radial deformation of the cement and casing. The semi-analytical model and the predictions are compared to the experimental data. Within the regime of linear elasticity, the radial deformation of the cell wall is proportional to the pressure in the micro-annulus. During leakage testing, the pressure-driven radial deformation of the cell materials is coupled to the variation of the liquid friction pressure gradient along the axial length of the micro-annulus. The pressure gradient is greatest at the outlet of the micro-annulus. The models presented have been used to improve the interpretation of fluid flow during micro-annulus leakage experiments. An improved understanding of fluid leakage mechanisms through micro-annuli can be applied to field cases such as the interpretation and choice of treatment for sustained casing pressure build-up.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"135 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75507320","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}
Peyman Asgari, A. C. Fernandes, J. S. Sales, Ana Clara Thurler, A. Vilela, J. B. Araujo
An innovative Oil Loading Terminal (OLT) system was recently developed to attend FPSOs (Floating, Production, Storage and Offloading) units up to 250.000 barrels/ day of oil production and operating in deep waters. This OLT allows offloading operations from the FPSOs onto Very Large Crude Carriers (VLCC) shuttle tankers moored in a Single Point Mooring Buoy type usually called CALM Buoy. The heart of this OLT concept is a tether anchored subsurface buoy - named BSL (Buoy for Supporting Lines) - application to support the submerged Oil Offloading Lines OOL segments between the FPSO and CALM Buoy. The BSL presence de-couples the motions of the two floating bodies. As a result, the OOLs loads and fatigue efforts also decrease on all connections. The fact is the submerged BSL will decrease the wave's impact on the design. It is important to recognize that all components are field proven and installable as described in [4]. The scope of this paper is to evaluate some different arrangement of the OLT submerged components to assess the level of influence of each one. This work will perform a parametric assessment of the main geometric and inertial characteristics of each component seeking consequences on the static and dynamic tensions in hot spots and the fatigue life on the main components. The first aspect to watch is related to the relative and total horizontal distances between the FPSO, BSL and CALM Buoy. The other is the depth of the BSL, followed by the floater length in both branches of the flexible lines. Geometries were tested in Santos basin, Brazil (2200m water depth). For each case an economic quantification is performed, since the best economic result may not coincide with the best tension and fatigue life. The proposed OLT should allow the employment of conventional tankers, either Suezmaxes or VLCCs, connected onto the FPSO via a CB and a BSL plus OOLs, by placing the largest fraction of the OOLs weight supported by the FPSO and BSL. The sections of the OOLs between the BSL and the FPSO can be of either steel or flexible; or even a combination of both. The use of BSL conception for the Brazilian offshore pre-salt area is in fact a reliable, safe and robust system when compared with the FPSO tandem offloading or the complementary Ship-to-Ship oil transfers.
{"title":"Parametric Assessment of the Buoy for Supporting Lines BSL Applied to Large FPSOs","authors":"Peyman Asgari, A. C. Fernandes, J. S. Sales, Ana Clara Thurler, A. Vilela, J. B. Araujo","doi":"10.4043/29923-ms","DOIUrl":"https://doi.org/10.4043/29923-ms","url":null,"abstract":"\u0000 An innovative Oil Loading Terminal (OLT) system was recently developed to attend FPSOs (Floating, Production, Storage and Offloading) units up to 250.000 barrels/ day of oil production and operating in deep waters. This OLT allows offloading operations from the FPSOs onto Very Large Crude Carriers (VLCC) shuttle tankers moored in a Single Point Mooring Buoy type usually called CALM Buoy. The heart of this OLT concept is a tether anchored subsurface buoy - named BSL (Buoy for Supporting Lines) - application to support the submerged Oil Offloading Lines OOL segments between the FPSO and CALM Buoy. The BSL presence de-couples the motions of the two floating bodies. As a result, the OOLs loads and fatigue efforts also decrease on all connections. The fact is the submerged BSL will decrease the wave's impact on the design. It is important to recognize that all components are field proven and installable as described in [4]. The scope of this paper is to evaluate some different arrangement of the OLT submerged components to assess the level of influence of each one.\u0000 This work will perform a parametric assessment of the main geometric and inertial characteristics of each component seeking consequences on the static and dynamic tensions in hot spots and the fatigue life on the main components. The first aspect to watch is related to the relative and total horizontal distances between the FPSO, BSL and CALM Buoy. The other is the depth of the BSL, followed by the floater length in both branches of the flexible lines. Geometries were tested in Santos basin, Brazil (2200m water depth). For each case an economic quantification is performed, since the best economic result may not coincide with the best tension and fatigue life.\u0000 The proposed OLT should allow the employment of conventional tankers, either Suezmaxes or VLCCs, connected onto the FPSO via a CB and a BSL plus OOLs, by placing the largest fraction of the OOLs weight supported by the FPSO and BSL. The sections of the OOLs between the BSL and the FPSO can be of either steel or flexible; or even a combination of both.\u0000 The use of BSL conception for the Brazilian offshore pre-salt area is in fact a reliable, safe and robust system when compared with the FPSO tandem offloading or the complementary Ship-to-Ship oil transfers.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"53 3-4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72631197","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}
This work explains the process of how a bit was designed specifically to address drilling challenges of the reservoir section of the Mero Field offshore Brazil. The performance of this new bit is compared to previous bits used in the field. A systematic process to design and evaluate the performance of a new bit involves interaction with the operator to understand the challenges and gather information, evaluate previous bit performances, use software to simulate the new bit design based on drilling conditions in the field, manufacture the bit according to design specifications, run the bit according to planned parameters, capture and report results, and evaluate results to identify possible improvements. The reservoir section has a high hardness and is primarily composed of calcareous rock and silica intercalations. Since the discovery of the Mero Field, more than 17 wells have been drilled by different companies. In the majority of the wells, the reservoir section was drilled using impregnated bits and turbines. As a result, the application of a systematic process was used to solve operator challenges where a new bit was designed and run in the field to drill the reservoir section of two wells. A comparison was performed between the previous bits used in the field and the new bit concept, certifying that the new bit reduced the reservoir section drilling time by 59%. This work discusses improved drilling efficiency in the reservoir section by drilling with a new bit design in a field where only impregnated bits and turbines were used. This created a new benchmark for drilling performance in the Mero Field.
{"title":"Setting a New Benchmark in ROP and Bit Durability in the Pre-Salt Section Carbonate Rocks of the Deepwater Mero Field in Brazil","authors":"N. Silva, A. Boulton","doi":"10.4043/29843-ms","DOIUrl":"https://doi.org/10.4043/29843-ms","url":null,"abstract":"\u0000 This work explains the process of how a bit was designed specifically to address drilling challenges of the reservoir section of the Mero Field offshore Brazil. The performance of this new bit is compared to previous bits used in the field.\u0000 A systematic process to design and evaluate the performance of a new bit involves interaction with the operator to understand the challenges and gather information, evaluate previous bit performances, use software to simulate the new bit design based on drilling conditions in the field, manufacture the bit according to design specifications, run the bit according to planned parameters, capture and report results, and evaluate results to identify possible improvements.\u0000 The reservoir section has a high hardness and is primarily composed of calcareous rock and silica intercalations. Since the discovery of the Mero Field, more than 17 wells have been drilled by different companies. In the majority of the wells, the reservoir section was drilled using impregnated bits and turbines. As a result, the application of a systematic process was used to solve operator challenges where a new bit was designed and run in the field to drill the reservoir section of two wells. A comparison was performed between the previous bits used in the field and the new bit concept, certifying that the new bit reduced the reservoir section drilling time by 59%.\u0000 This work discusses improved drilling efficiency in the reservoir section by drilling with a new bit design in a field where only impregnated bits and turbines were used. This created a new benchmark for drilling performance in the Mero Field.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81590996","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}
When defining the subsea arrangement for a gas export system, a few options are available to connect a trunk gas pipeline to other pipelines or to FPUs, especially when there is uncertainty about future projects which may need to be connected to the export system. The objective of this paper is to present an assessment of different options based on a case study. A matrix will be generated pointing the pros and cons of different technical solutions regarding aspects such as: economicity for long and short distances, total length of pipelines, number of subsea structures, technology maturity, risks related to QHSE issues, risks to assets during installation, interruption of gas export during installation, construction duration and availability to deepwater. Considerations about the applicability and relative importance of each of the above mentioned parameters will also be included. Examples of subsea arrangements and strategies of acquisition for gas export systems projects include: using ILTs/ILYs for each connection; using ILTs/ILYs and PLEMs "offline", i.e., PLEMs with several hubs connected to in-line structures along the trunk pipeline; using PLEMs in-line, i.e., PLEMs connected directly to the trunk line, by means of rigid or flexible jumpers and PLETs; using diver assisted or diverless cut after hot tapping; using diver assisted or diverless cut in conjunction with smart plugs. Finally, nonconventional alternatives to export the gas like LNG, CNG, GTW or GTL will also be assessed. The results will present guidelines on how to select the most appropriate subsea arrangement for gas export systems, depending on the specificities of each project, such as: the extension of the field, the distance to shore, the maturity level of the present and future (interconnected) projects, the water depth, the distance between FPUs and others.
{"title":"Subsea Arrangements Optimization for Gas Export Systems","authors":"Carlos Patusco, E. F. Simões","doi":"10.4043/29903-ms","DOIUrl":"https://doi.org/10.4043/29903-ms","url":null,"abstract":"\u0000 When defining the subsea arrangement for a gas export system, a few options are available to connect a trunk gas pipeline to other pipelines or to FPUs, especially when there is uncertainty about future projects which may need to be connected to the export system. The objective of this paper is to present an assessment of different options based on a case study. A matrix will be generated pointing the pros and cons of different technical solutions regarding aspects such as: economicity for long and short distances, total length of pipelines, number of subsea structures, technology maturity, risks related to QHSE issues, risks to assets during installation, interruption of gas export during installation, construction duration and availability to deepwater. Considerations about the applicability and relative importance of each of the above mentioned parameters will also be included. Examples of subsea arrangements and strategies of acquisition for gas export systems projects include: using ILTs/ILYs for each connection; using ILTs/ILYs and PLEMs \"offline\", i.e., PLEMs with several hubs connected to in-line structures along the trunk pipeline; using PLEMs in-line, i.e., PLEMs connected directly to the trunk line, by means of rigid or flexible jumpers and PLETs; using diver assisted or diverless cut after hot tapping; using diver assisted or diverless cut in conjunction with smart plugs. Finally, nonconventional alternatives to export the gas like LNG, CNG, GTW or GTL will also be assessed. The results will present guidelines on how to select the most appropriate subsea arrangement for gas export systems, depending on the specificities of each project, such as: the extension of the field, the distance to shore, the maturity level of the present and future (interconnected) projects, the water depth, the distance between FPUs and others.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82065313","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}
Raphael Beppler Veloso, Alexandre Rabello Pereira, Marcello Ramos Roberto Augustus
Subsea X-Mas Trees have been standardized in Brazil since the 1990’s and this paper will present how this standardization was evolved throughout the years and the main benefits achieved to both, the operator and the suppliers. To achieve the standardization benefits the X-Mas Trees standardization program has followed three main approaches: -The first is related to standardization of X-Mas Tree application, becoming it possible to use any X-mas Tree from any supplier in the production or injection wells, in the most possible cases.-The Second is related to standardization of X-Mas Tree interfaces between sub-equipment and between the equipment and its tools.-The third is related to standardization of manufacturing, qualification program and inspection. At the beginning, only the interfaces between the THS (Tubing Head Spool), TH (Tubing Hanger) and the X-Mas Tree itself were standardized. Throughout the years, more interfaces were standardized, such as Tree Cap, Flowline Connectors and Control Systems. The standardization may lead to very big scale gains and cost reduction when is possible to look the whole projects as a portfolio, as it makes possible to combine several projects into a Bidding process (bid), enabling better competitiveness in the supplier market. For example, bids with up to 300 X-Mas Trees split in lots with up to around 130 X-Mas Tree per supplier were carried out in Post-Salt and Pre-salt projects and a huge benefit was achieved with this strategy. In addition, the standardization brings better stock management as the projects’ schedule changes over time, minimizing the time the X-Mas Trees stay in stock. At last, it enables faster project implementation, once the equipment is already contracted, designed and, sometimes, even manufactured. Standardization of the X-Mas interfaces brings the possibility of exchanging sub-equipment of different suppliers, as vertical connector modules, for example, between any well. This is extremely useful when there are operational issues during the installation, as it becomes possible to use equipment from another supplier until the issue is outlined. Besides that, there is another standardization benefit, regarding to wells maintenance, where the equipment removed from a well can technically be reused in another well. Additionally, when multiplexed X-Mas Trees became the standard in Brazil for Pre-Salt wells (in the past, all multiplexed controls were located on Manifolds), it was imperative to standardize the control system interfaces, enabling it to be from a different supplier than the X-Mas Tree itself, as well. Standardization of X-Mas Trees enabled the operator to better answer to its projects demand in a portfolio view, reducing costs, increasing flexibility and allowing the competitiveness between suppliers in all project phases.
{"title":"Subsea X-Mas Tree Standardization Benefits in Brazil Scenario","authors":"Raphael Beppler Veloso, Alexandre Rabello Pereira, Marcello Ramos Roberto Augustus","doi":"10.4043/29872-ms","DOIUrl":"https://doi.org/10.4043/29872-ms","url":null,"abstract":"\u0000 Subsea X-Mas Trees have been standardized in Brazil since the 1990’s and this paper will present how this standardization was evolved throughout the years and the main benefits achieved to both, the operator and the suppliers.\u0000 To achieve the standardization benefits the X-Mas Trees standardization program has followed three main approaches: -The first is related to standardization of X-Mas Tree application, becoming it possible to use any X-mas Tree from any supplier in the production or injection wells, in the most possible cases.-The Second is related to standardization of X-Mas Tree interfaces between sub-equipment and between the equipment and its tools.-The third is related to standardization of manufacturing, qualification program and inspection.\u0000 At the beginning, only the interfaces between the THS (Tubing Head Spool), TH (Tubing Hanger) and the X-Mas Tree itself were standardized. Throughout the years, more interfaces were standardized, such as Tree Cap, Flowline Connectors and Control Systems.\u0000 The standardization may lead to very big scale gains and cost reduction when is possible to look the whole projects as a portfolio, as it makes possible to combine several projects into a Bidding process (bid), enabling better competitiveness in the supplier market. For example, bids with up to 300 X-Mas Trees split in lots with up to around 130 X-Mas Tree per supplier were carried out in Post-Salt and Pre-salt projects and a huge benefit was achieved with this strategy.\u0000 In addition, the standardization brings better stock management as the projects’ schedule changes over time, minimizing the time the X-Mas Trees stay in stock. At last, it enables faster project implementation, once the equipment is already contracted, designed and, sometimes, even manufactured.\u0000 Standardization of the X-Mas interfaces brings the possibility of exchanging sub-equipment of different suppliers, as vertical connector modules, for example, between any well. This is extremely useful when there are operational issues during the installation, as it becomes possible to use equipment from another supplier until the issue is outlined. Besides that, there is another standardization benefit, regarding to wells maintenance, where the equipment removed from a well can technically be reused in another well.\u0000 Additionally, when multiplexed X-Mas Trees became the standard in Brazil for Pre-Salt wells (in the past, all multiplexed controls were located on Manifolds), it was imperative to standardize the control system interfaces, enabling it to be from a different supplier than the X-Mas Tree itself, as well.\u0000 Standardization of X-Mas Trees enabled the operator to better answer to its projects demand in a portfolio view, reducing costs, increasing flexibility and allowing the competitiveness between suppliers in all project phases.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"56 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79951000","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. M. Passarelli, Denise Adelina Guimaraes Moura, A. M. Bidart, Juliana Pereira Silva, A. Vieira, Luis Felipe Alves Frutuoso
Some deepwater Offshore reservoir contain fluids with high Gas-Oil Ratio (GOR) and CO2 content, presenting also a high productivity index (PI) like the ones found in Brazilian Presalt area. All these leads to large production facilities with complex gas processing section, thus constraining the oil processing and storage capacities. In these scenarios, the application of the HISEPTM, a high pressure, dense phase separation technology patented by PETROBRAS enhances production by promptly enabling the separation and reinjection of a major fraction of this CO2-rich associated gas on the seabed as a dense fluid, hence reducing the need for large gas processing plant in the topside, which in turn extends the oil production plateau and accelerates the production.
{"title":"HISEP: A Game Changer to Boost the Oil Production of High GOR and High CO2 Content Reservoirs","authors":"F. M. Passarelli, Denise Adelina Guimaraes Moura, A. M. Bidart, Juliana Pereira Silva, A. Vieira, Luis Felipe Alves Frutuoso","doi":"10.4043/29762-ms","DOIUrl":"https://doi.org/10.4043/29762-ms","url":null,"abstract":"\u0000 Some deepwater Offshore reservoir contain fluids with high Gas-Oil Ratio (GOR) and CO2 content, presenting also a high productivity index (PI) like the ones found in Brazilian Presalt area. All these leads to large production facilities with complex gas processing section, thus constraining the oil processing and storage capacities. In these scenarios, the application of the HISEPTM, a high pressure, dense phase separation technology patented by PETROBRAS enhances production by promptly enabling the separation and reinjection of a major fraction of this CO2-rich associated gas on the seabed as a dense fluid, hence reducing the need for large gas processing plant in the topside, which in turn extends the oil production plateau and accelerates the production.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87124731","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}
Rotary steerable tool has been proved reliable tool that can be used in different types of formation. But in the Rio Del Rey area in the "Benin sand" in Offshore Cameroon, directional drilling issue have been faced while drilling with rotary steerable tool. This paper present a case of study on the importance of the Bottom Hole Assembly choice versus the lithology, BHA Configuration, bit selection and trajectory requirements. Also based on lessons learned, propose some recommendations. Rotary steerable is deemed to be a reliable tool that can be used on most of type of formation but this is not always the case as shown in our case of study while drilling through the Benin sand formation which is a shallow formation in Rio Del Rey field in the Niger Delta, offshore Cameroon using the rotary steerable system. RSS BHA has been observed to perform below expectations while drilling this formation. A holistic review of the operational performance of the five Bottom Hole Assembly that was run in the hole to drill ~1000m of soft sandy formation will be summarized. We will analyze each BHA that was ran in hole and the performance achieved. Also BHA configuration and trajectory will be evaluated and reviewed. Finally, some recommendation are made. In addition, the choice of bit selected and performance will be evaluated. After detailed analysis of each BHA, RSS BHA with PDC bit was seen not to be a good choice of BHA to drill through the Benin sand formation based on the well directional objectives and BUR requirements. Motor BHA with tricone bit using the principle of jetting was used along with catenary design trajectory. This BHA and bit selection choice with catenary design trajectory helped to achieve the directional objective 100%, even exceeded the required DLS at some point. Also, adjusting drilling parameters contributed to the success seen so far. However, some irregularity was observed in the dogleg severity which may need an additional run with the rotary steerable system to smoothen the trajectory or perform a control trip in this soft formation with the potential risk of accidental sidetrack. In conclusion, a Motor bottom hole assembly with tricone bit using the principle of jetting should be used if a risk of collision is highlighted and a need to build up quickly in order to move away faster from nearest wells. A motor assembly is more recommended in soft shallow formation (0m −700m TVD) than the rotary steerable system. A better BUR behavior was observed with a motor assembly. This paper will serve as a guide / recommendation for any drilling that requireds an aggressive shallow kick off due to collision concern in soft shallow surface formation where performance of the bottom hole assembly and bit selection is critical.
旋转导向工具已被证明是一种可靠的工具，可用于不同类型的地层。但在喀麦隆海上“贝宁砂”的Rio Del Rey地区，使用旋转导向工具钻井时面临定向钻井问题。本文介绍了一个研究案例，研究了井底钻具组合选择与岩性、BHA配置、钻头选择和轨迹要求的重要性。同时根据经验教训，提出一些建议。旋转导向系统被认为是一种可靠的工具，可用于大多数类型的地层，但并非总是如此，正如我们在尼日尔三角洲Rio Del Rey油田使用旋转导向系统钻探贝宁砂层时所展示的情况。贝宁砂层是一个浅层地层。在钻井该地层时，RSS BHA的性能低于预期。本文将对5套底部钻具组合的作业性能进行全面回顾，这些钻具组合在该井中钻入了约1000m的软砂地层。我们将分析下入的每个BHA以及所取得的性能。此外，还将评估和审查BHA的配置和轨迹。最后，提出了一些建议。此外，还将对所选钻头的选择和性能进行评估。在对每个BHA进行详细分析后，根据井的定向目标和BUR要求，RSS BHA与PDC钻头并不是钻穿贝宁砂层的好选择。采用喷流原理的三牙轮马达BHA配合悬链线设计轨迹。采用悬链线设计轨迹的BHA和钻头选择有助于100%实现定向目标，甚至在某些时候超过了要求的DLS。此外，钻井参数的调整也为迄今为止的成功做出了贡献。然而，在狗腿的严重程度上，观察到一些不规律，这可能需要使用旋转导向系统进行额外的下入，以平滑轨迹或在这种软地层中进行控制起下钻，这可能存在意外侧钻的风险。综上所述，如果存在碰撞风险，并且需要快速积累，以便更快地离开最近的井，则应使用基于喷射原理的带有三牙轮钻头的马达底部钻具组合。相比旋转导向系统，在软浅层地层(TVD为0 ~ 700m)中更推荐使用电机组件。使用电机组件观察到更好的BUR行为。对于在软浅地层中，由于担心碰撞而需要积极的浅井起下钻的钻井，本文将作为指导/建议，因为底部钻具组合的性能和钻头的选择至关重要。
{"title":"A Study of Directional Drilling Using Rotary Steerable System in Soft Shallow Formation Benin Sand – Rio Del Rey Area, Offshore Cameroon","authors":"O. Oredolapo, Claude Placide Onomo","doi":"10.4043/29750-ms","DOIUrl":"https://doi.org/10.4043/29750-ms","url":null,"abstract":"\u0000 Rotary steerable tool has been proved reliable tool that can be used in different types of formation. But in the Rio Del Rey area in the \"Benin sand\" in Offshore Cameroon, directional drilling issue have been faced while drilling with rotary steerable tool.\u0000 This paper present a case of study on the importance of the Bottom Hole Assembly choice versus the lithology, BHA Configuration, bit selection and trajectory requirements. Also based on lessons learned, propose some recommendations.\u0000 Rotary steerable is deemed to be a reliable tool that can be used on most of type of formation but this is not always the case as shown in our case of study while drilling through the Benin sand formation which is a shallow formation in Rio Del Rey field in the Niger Delta, offshore Cameroon using the rotary steerable system. RSS BHA has been observed to perform below expectations while drilling this formation. A holistic review of the operational performance of the five Bottom Hole Assembly that was run in the hole to drill ~1000m of soft sandy formation will be summarized. We will analyze each BHA that was ran in hole and the performance achieved. Also BHA configuration and trajectory will be evaluated and reviewed. Finally, some recommendation are made. In addition, the choice of bit selected and performance will be evaluated.\u0000 After detailed analysis of each BHA, RSS BHA with PDC bit was seen not to be a good choice of BHA to drill through the Benin sand formation based on the well directional objectives and BUR requirements. Motor BHA with tricone bit using the principle of jetting was used along with catenary design trajectory. This BHA and bit selection choice with catenary design trajectory helped to achieve the directional objective 100%, even exceeded the required DLS at some point. Also, adjusting drilling parameters contributed to the success seen so far.\u0000 However, some irregularity was observed in the dogleg severity which may need an additional run with the rotary steerable system to smoothen the trajectory or perform a control trip in this soft formation with the potential risk of accidental sidetrack.\u0000 In conclusion, a Motor bottom hole assembly with tricone bit using the principle of jetting should be used if a risk of collision is highlighted and a need to build up quickly in order to move away faster from nearest wells.\u0000 A motor assembly is more recommended in soft shallow formation (0m −700m TVD) than the rotary steerable system. A better BUR behavior was observed with a motor assembly.\u0000 This paper will serve as a guide / recommendation for any drilling that requireds an aggressive shallow kick off due to collision concern in soft shallow surface formation where performance of the bottom hole assembly and bit selection is critical.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91451707","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 objective of the paper is to explain the need of standardisation in design and construction of Topsides for FPSO. The main target is to reduce design error, improve engineering process, support procurement and ensure repeatability. The scope of this paper focuses on the complex design process that is required to be performed at conceptual and FEED stage, then further carried over to Detailed Engineering, Procurement, Construction, Commissioning and Operation stages. This s focuses on specification and standardisations involved across all disciplines including mechanical, piping, structure, instrumentation and electrical. The utilisation of the standard will be taking place at all levels, namely Module, System and Equipment. The approach concentrates on the deployment of these engineering standards and specifications early on so that they can be used throughout the project. The information is to be made available in the form of guidelines. The second part of standardisation is at component or product level. In order to streamline the diversity of the options, the standardisation is the substance to reduce variety by specifying the component that will be associated with the equipment, system and module. There is tremendous reduction of work when commonality is implemented across the topside. ‘Construction hat’ thinking was one of the features in standardisation. We encourage two-way discussion and feedback with fabrication and construction. Apart from ensuring the constructability, the ability to source the material is one of the important benefits. Similarly, for Operation, close relationship with the operator will ensure the operability and maintainability of the asset that has been constructed. Through the implementation of these engineering standards and specifications, one avoids performing unnecessary basic engineering works. For example, piping specifications that we generate are based on pipe specification from standards (e.g. API, B31.3). Specific project requirements may result in changes to these standard industry specifications.
{"title":"FPSO Topside Standardisation","authors":"Rosdi Baharim, John Ernest Leemeijer","doi":"10.4043/29773-ms","DOIUrl":"https://doi.org/10.4043/29773-ms","url":null,"abstract":"\u0000 The objective of the paper is to explain the need of standardisation in design and construction of Topsides for FPSO. The main target is to reduce design error, improve engineering process, support procurement and ensure repeatability.\u0000 The scope of this paper focuses on the complex design process that is required to be performed at conceptual and FEED stage, then further carried over to Detailed Engineering, Procurement, Construction, Commissioning and Operation stages. This s focuses on specification and standardisations involved across all disciplines including mechanical, piping, structure, instrumentation and electrical. The utilisation of the standard will be taking place at all levels, namely Module, System and Equipment. The approach concentrates on the deployment of these engineering standards and specifications early on so that they can be used throughout the project. The information is to be made available in the form of guidelines.\u0000 The second part of standardisation is at component or product level. In order to streamline the diversity of the options, the standardisation is the substance to reduce variety by specifying the component that will be associated with the equipment, system and module. There is tremendous reduction of work when commonality is implemented across the topside.\u0000 ‘Construction hat’ thinking was one of the features in standardisation. We encourage two-way discussion and feedback with fabrication and construction. Apart from ensuring the constructability, the ability to source the material is one of the important benefits. Similarly, for Operation, close relationship with the operator will ensure the operability and maintainability of the asset that has been constructed.\u0000 Through the implementation of these engineering standards and specifications, one avoids performing unnecessary basic engineering works. For example, piping specifications that we generate are based on pipe specification from standards (e.g. API, B31.3). Specific project requirements may result in changes to these standard industry specifications.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87224786","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}
Severe slugging is a cyclic flow regime which causes intermittent delivery of oil and gas which usually leads to flow separator flooding, production reduction, platform trips and plant shutdown. This paper presents a novel method for severe slugging mitigation. It describes the use of a Venturi for the improvement of system stability, increase in production and recovery. A Venturi is coupled to the pipeline-riser system upstream of the choke valve before the topside test separator for severe slug mitigation. Experiments were carried out in a 2″ pipeline-riser system which comprises of a 40 m long horizontal pipe connected to a 10.23 m high S-shape riser followed by a 5.2 m horizontal topside section. The effects of Venturi on severe slugging were investigated, gas perturbation method was used to analyse the effects of Venturi on the stability of the system, and the traditional choking technique and Hopf bifurcation technique were combined and used to investigate the stability and production increase performance of the pipeline-riser with Venturi applied. Experimental results show that with the Venturi applied, the system achieves stability quicker than without the Venturi in the pipeline-riser and reduced the pressure fluctuation range by 57 %. In addition, combining the Venturi with the choke valve to choke the pipeline-riser (bifurcation study) stabilised the system at higher valve opening and lower pressure compared to choking the pipeline-riser with the choke valve only. For the case studied (Vsl = 0.25 m/s and Vsg = 0.37 m/s) bifurcation (critical valve opening) occurred at 18 % valve opening and average riser base pressure value of 2.8 barg for the plain riser. However, with Venturi applied bifurcation occurred at a larger valve opening of 21% and a lower average riser base pressure value of 2.5 barg. The low loss of energy due to the gradual change in geometry of the Venturi may account for its ability to achieve stability at a lower riser base pressure. Thus, Venturi increased the valve opening by 17% and reduced the riser base pressure by 11%. These in practice translate to an increase in oil and gas production. This is a cost-effective severe slug mitigation method, its deployment at the topside is an additional advantage when compared with other methods that require subsea deployment. The increase in brown fields due to diminishing reserves of oil from reservoirs have made oil recovery very vital. This technique will help to extend the operational life of a reservoir, thus enhancing oil recovery and flow assurance.
{"title":"Severe Slugging Mitigation in an S-Shape Pipeline-Riser System With a Venturi for Increased Production and Recovery","authors":"Joseph Inok, Liyun Lao, Yi Cao, J. Whidborne","doi":"10.4043/29907-ms","DOIUrl":"https://doi.org/10.4043/29907-ms","url":null,"abstract":"Severe slugging is a cyclic flow regime which causes intermittent delivery of oil and gas which usually leads to flow separator flooding, production reduction, platform trips and plant shutdown. This paper presents a novel method for severe slugging mitigation. It describes the use of a Venturi for the improvement of system stability, increase in production and recovery. A Venturi is coupled to the pipeline-riser system upstream of the choke valve before the topside test separator for severe slug mitigation. Experiments were carried out in a 2″ pipeline-riser system which comprises of a 40 m long horizontal pipe connected to a 10.23 m high S-shape riser followed by a 5.2 m horizontal topside section. The effects of Venturi on severe slugging were investigated, gas perturbation method was used to analyse the effects of Venturi on the stability of the system, and the traditional choking technique and Hopf bifurcation technique were combined and used to investigate the stability and production increase performance of the pipeline-riser with Venturi applied. Experimental results show that with the Venturi applied, the system achieves stability quicker than without the Venturi in the pipeline-riser and reduced the pressure fluctuation range by 57 %. In addition, combining the Venturi with the choke valve to choke the pipeline-riser (bifurcation study) stabilised the system at higher valve opening and lower pressure compared to choking the pipeline-riser with the choke valve only. For the case studied (Vsl = 0.25 m/s and Vsg = 0.37 m/s) bifurcation (critical valve opening) occurred at 18 % valve opening and average riser base pressure value of 2.8 barg for the plain riser. However, with Venturi applied bifurcation occurred at a larger valve opening of 21% and a lower average riser base pressure value of 2.5 barg. The low loss of energy due to the gradual change in geometry of the Venturi may account for its ability to achieve stability at a lower riser base pressure. Thus, Venturi increased the valve opening by 17% and reduced the riser base pressure by 11%. These in practice translate to an increase in oil and gas production. This is a cost-effective severe slug mitigation method, its deployment at the topside is an additional advantage when compared with other methods that require subsea deployment. The increase in brown fields due to diminishing reserves of oil from reservoirs have made oil recovery very vital. This technique will help to extend the operational life of a reservoir, thus enhancing oil recovery and flow assurance.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81169305","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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