Sílvia Lima Touma, Juliana Casaccia Vaz, Frederico Carvalho De Almeida Rego, V. Barros, J. F. Nascimento, Marcelo da Costa Amaral, Eduardo Conde De Miranda Costa, André Felipe Ferreira De Souza
Libra Area has presented gas/oil ratio (GOR) and CO2 content higher than the typically found in other Pre-Salt fields. These characteristics can significantly increase the size and complexity of the gas processing plant (GPP), especially in gas export scenarios. More efficient gas treatment technologies and with the ability to handle high CO2 levels need to be developed to reduce footprint and weight, improving oil plant capacity. This paper presents two membrane technologies selected for evaluation: Carbon Molecular Sieve (CMS), a partnership with Shell focused on CO2 removal, and All Membrane Solution (AMSTM), a commercial Air Liquide solution that can optimize the GPP layout by replacing conventional processes used for contaminants removal. AMS aims to remove, not only CO2, but also other contaminants such as H2S, H2O, and heavy hydrocarbons. Both technologies promise to lower the CAPEX and OPEX while increasing the oil production capacity, leading to more economically attractive projects. The demonstrations will be carried out at Atalaia Experimental Nucleus (NEAT), which is a Petrobras’ center for gas technology assessment, located in Aracaju city, Brazil. Pilot-scale skids operating under Libra typical gas conditions will be used for technology assessment. CMS and AMS will be tested sequentially, the former expected to start in the second half of 2019 and the latter in the first half of 2020. For CMS technology, further tests on an industrial-scale prototype will still be needed afterwards, whereas for AMS, due to its higher technology readiness level (TRL), it is expected that it can be implemented just after the demonstration.
{"title":"Innovative Gas Treatment Solutions for Offshore Systems","authors":"Sílvia Lima Touma, Juliana Casaccia Vaz, Frederico Carvalho De Almeida Rego, V. Barros, J. F. Nascimento, Marcelo da Costa Amaral, Eduardo Conde De Miranda Costa, André Felipe Ferreira De Souza","doi":"10.4043/29913-ms","DOIUrl":"https://doi.org/10.4043/29913-ms","url":null,"abstract":"\u0000 Libra Area has presented gas/oil ratio (GOR) and CO2 content higher than the typically found in other Pre-Salt fields. These characteristics can significantly increase the size and complexity of the gas processing plant (GPP), especially in gas export scenarios. More efficient gas treatment technologies and with the ability to handle high CO2 levels need to be developed to reduce footprint and weight, improving oil plant capacity. This paper presents two membrane technologies selected for evaluation: Carbon Molecular Sieve (CMS), a partnership with Shell focused on CO2 removal, and All Membrane Solution (AMSTM), a commercial Air Liquide solution that can optimize the GPP layout by replacing conventional processes used for contaminants removal. AMS aims to remove, not only CO2, but also other contaminants such as H2S, H2O, and heavy hydrocarbons. Both technologies promise to lower the CAPEX and OPEX while increasing the oil production capacity, leading to more economically attractive projects. The demonstrations will be carried out at Atalaia Experimental Nucleus (NEAT), which is a Petrobras’ center for gas technology assessment, located in Aracaju city, Brazil. Pilot-scale skids operating under Libra typical gas conditions will be used for technology assessment. CMS and AMS will be tested sequentially, the former expected to start in the second half of 2019 and the latter in the first half of 2020. For CMS technology, further tests on an industrial-scale prototype will still be needed afterwards, whereas for AMS, due to its higher technology readiness level (TRL), it is expected that it can be implemented just after the demonstration.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89518212","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}
Walter Carrara Loureiro, Rafael Guimarães De Mello Sobreira, Adriana Loureiro da Silva Buckley
Large diameter UDW flexible pipes usually require lazy-wave configuration to withstand operational fatigue life. In a response to the current uncertain oil/gas price, the opportunity to design and deploy Free Hanging Catenary risers has been identified as the means to significantly lower CAPEX of flexible risers installed while securing the required life-cycle performance, including optimized offshore installation, 30-year fatigue duties. The most promising concepts to deliver free hanging configuration are based on composite flexible pipe designs, but these solutions rely on new technology (or at least new application of technology) and will need to undergo all new technology development phases including "Field Qualification" stage before they are ready to be considered as a base case for any UDW Project. Composite flexible pipe considers the adoption of new composite materials layers replacing one or multiple layers of a conventional flexible pipe for at least one pipe section. Several new hybrid pipe concepts can be developed considering this approach. Considering current Industry Standards and Brazil Regulations many challenges can be identified to deploy this type of new technology. These pipe concepts do not fit in the definition of existing Standards. In addition, the unknown behavior of these material and layers in a flexible pipe will increase the integrity assessment complexity. During the development phase the integrity assessment challenges and potential gaps in industry standards will have to be addressed as well to avoid misalignment or conflicts with regulatory requirements.
{"title":"Hybrid Composite Flexible Risers in Free Hanging Catenary Configuration and Flowlines for UDW Projects","authors":"Walter Carrara Loureiro, Rafael Guimarães De Mello Sobreira, Adriana Loureiro da Silva Buckley","doi":"10.4043/29906-ms","DOIUrl":"https://doi.org/10.4043/29906-ms","url":null,"abstract":"\u0000 Large diameter UDW flexible pipes usually require lazy-wave configuration to withstand operational fatigue life. In a response to the current uncertain oil/gas price, the opportunity to design and deploy Free Hanging Catenary risers has been identified as the means to significantly lower CAPEX of flexible risers installed while securing the required life-cycle performance, including optimized offshore installation, 30-year fatigue duties.\u0000 The most promising concepts to deliver free hanging configuration are based on composite flexible pipe designs, but these solutions rely on new technology (or at least new application of technology) and will need to undergo all new technology development phases including \"Field Qualification\" stage before they are ready to be considered as a base case for any UDW Project.\u0000 Composite flexible pipe considers the adoption of new composite materials layers replacing one or multiple layers of a conventional flexible pipe for at least one pipe section. Several new hybrid pipe concepts can be developed considering this approach. Considering current Industry Standards and Brazil Regulations many challenges can be identified to deploy this type of new technology. These pipe concepts do not fit in the definition of existing Standards. In addition, the unknown behavior of these material and layers in a flexible pipe will increase the integrity assessment complexity.\u0000 During the development phase the integrity assessment challenges and potential gaps in industry standards will have to be addressed as well to avoid misalignment or conflicts with regulatory requirements.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86132926","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}
B. Cavalcante, J. S. Baioco, B. P. Jacob, Nicolas Paes Urupukina
In an oil field development, the choice of the appropriate artificial lift method is extremely important to obtain the best financial return for the project. The most efficient artificial lift method for heavy oil is the ESP, in the perspective of lift capacity and flow assurance, but, due to its low MTTF (Mean Time to Failure), in some cases, the associated cost for the offshore workovers is prohibitive. An alternative to reduce the cost of the workover is positioning the ESP in the seabed, in a pumping skid (Subsea ESP / skid-ESP). Positioning the ESP in the seabed, however, reduces the initial well flow rate. Most commonly, the Artificial Lift Method is chosen based on the previews experience of the operator, not giving appropriate effort to a technical and commercial evaluation. This paper proposes a methodology to provide quantitative data to assist the decision of the best positioning of the pumping system, inside the well or on the seabed, in order to obtain the best financial return. The methodology is based on three stages: technical evaluation, which is an eliminatory step, based on the GVF (Gas Volume Fraction) limit that the pump can handle without flowing problems; then, an economical and risk analysis are performed for both projects (ESP and skid-ESP). Three case studies were performed to evaluate the proposed methodology, and to confirm that it is a good tool to assist the decision of the best positioning of the pumping system. The results show that the three stages proposed are important. One of the three cases show a scenario where the skid-ESP is declassified in the first step of the methodology because of the high GVF calculated for the project, above the limit for this specific well. In the other two cases all the three stages of the methodology were applied. The economical deterministic analysis was not enough to define the best positioning of the pumping system, in order to obtain the highest financial return, and the probabilistic risk analysis was essential to obtain quantitative data to support an efficient decision. In both cases the suggested positioning of the pumping system was the seabed (skid-ESP or subsea ESP). In the literature, some works propose methodologies to choose the appropriate artificial lift method. Some of them offer an economical evaluation tool; but a methodology that includes the subsea ESP as an option for heavy oil deep water projects was not found in the literature. This paper proposes a methodology that can be easily applied with the software's commonly used in the industry, therefore adding information to the existing body of literature that can benefit practicing engineers.
{"title":"Technical Economical and Risk Analysis Methodology for Defining the Optimum Positioning of the Electrical Submersible Pump System for Production of Heavy Oil in Deep Water","authors":"B. Cavalcante, J. S. Baioco, B. P. Jacob, Nicolas Paes Urupukina","doi":"10.4043/29775-ms","DOIUrl":"https://doi.org/10.4043/29775-ms","url":null,"abstract":"\u0000 In an oil field development, the choice of the appropriate artificial lift method is extremely important to obtain the best financial return for the project. The most efficient artificial lift method for heavy oil is the ESP, in the perspective of lift capacity and flow assurance, but, due to its low MTTF (Mean Time to Failure), in some cases, the associated cost for the offshore workovers is prohibitive. An alternative to reduce the cost of the workover is positioning the ESP in the seabed, in a pumping skid (Subsea ESP / skid-ESP). Positioning the ESP in the seabed, however, reduces the initial well flow rate. Most commonly, the Artificial Lift Method is chosen based on the previews experience of the operator, not giving appropriate effort to a technical and commercial evaluation. This paper proposes a methodology to provide quantitative data to assist the decision of the best positioning of the pumping system, inside the well or on the seabed, in order to obtain the best financial return.\u0000 The methodology is based on three stages: technical evaluation, which is an eliminatory step, based on the GVF (Gas Volume Fraction) limit that the pump can handle without flowing problems; then, an economical and risk analysis are performed for both projects (ESP and skid-ESP). Three case studies were performed to evaluate the proposed methodology, and to confirm that it is a good tool to assist the decision of the best positioning of the pumping system.\u0000 The results show that the three stages proposed are important. One of the three cases show a scenario where the skid-ESP is declassified in the first step of the methodology because of the high GVF calculated for the project, above the limit for this specific well. In the other two cases all the three stages of the methodology were applied. The economical deterministic analysis was not enough to define the best positioning of the pumping system, in order to obtain the highest financial return, and the probabilistic risk analysis was essential to obtain quantitative data to support an efficient decision. In both cases the suggested positioning of the pumping system was the seabed (skid-ESP or subsea ESP).\u0000 In the literature, some works propose methodologies to choose the appropriate artificial lift method. Some of them offer an economical evaluation tool; but a methodology that includes the subsea ESP as an option for heavy oil deep water projects was not found in the literature. This paper proposes a methodology that can be easily applied with the software's commonly used in the industry, therefore adding information to the existing body of literature that can benefit practicing engineers.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73306611","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
P. E. G. Panta, Rafaela Campos Furtado, J. Moreira
This paper approaches the challenges of temporarily abandoned well monitoring with wet christmas tree (WCT), analyzes the regulatory requirements, the Brazilian scenario and proposes a new methodology system to checking the two Well Safety Barriers (WSB) integrity as required by the ANP (Petroleum National Agency, the regulatory institution in Brazil) resolution nO46/2016. So, the system is compared with other monitoring alternatives, even economically, namely: using rigs or plugging and abandonment. A system is presented that allow the monitoring by means of WCT chamber pressurization or depressurization, hydrocarbons detection, leak measuring by control valves, measuring the WTC chambers pressure, collecting the probable hydrocarbons in a safety way and, and if required, actuating some WTC valves. The control valves and WTC chambers are accessed by the Vertical Connection Module (VCM) mandrel where a modified abandonment cap will be installed with a Control Module on the top. An isolation valve is installed in the Control Module, as a WSB redundancy. The monitoring system avoids the use of expensive intervention rigs and allow the indefinite postponement of plugging and abandonment, entailing sensible economic gains. In addition, the control module installation is made along with the abandonment cap, therefore, no additional cost is required. Another main issue is that the control module monitoring not entails significative impact in the time of well inspection routine. Besides fulfills the legal requirement, the monitoring system provides safety in operations and economic gains when compared to other alternatives. The proposed system patent has been deposited in Brazil. The economy and safety offered by the monitoring system doesn´t have similarities to the existing methodologies in the international market. However, it will be necessary a test prototype to develop.
{"title":"Abandoned Well Monitoring System with Wet Christmas Tree","authors":"P. E. G. Panta, Rafaela Campos Furtado, J. Moreira","doi":"10.4043/29878-ms","DOIUrl":"https://doi.org/10.4043/29878-ms","url":null,"abstract":"\u0000 This paper approaches the challenges of temporarily abandoned well monitoring with wet christmas tree (WCT), analyzes the regulatory requirements, the Brazilian scenario and proposes a new methodology system to checking the two Well Safety Barriers (WSB) integrity as required by the ANP (Petroleum National Agency, the regulatory institution in Brazil) resolution nO46/2016. So, the system is compared with other monitoring alternatives, even economically, namely: using rigs or plugging and abandonment. A system is presented that allow the monitoring by means of WCT chamber pressurization or depressurization, hydrocarbons detection, leak measuring by control valves, measuring the WTC chambers pressure, collecting the probable hydrocarbons in a safety way and, and if required, actuating some WTC valves. The control valves and WTC chambers are accessed by the Vertical Connection Module (VCM) mandrel where a modified abandonment cap will be installed with a Control Module on the top. An isolation valve is installed in the Control Module, as a WSB redundancy. The monitoring system avoids the use of expensive intervention rigs and allow the indefinite postponement of plugging and abandonment, entailing sensible economic gains. In addition, the control module installation is made along with the abandonment cap, therefore, no additional cost is required. Another main issue is that the control module monitoring not entails significative impact in the time of well inspection routine. Besides fulfills the legal requirement, the monitoring system provides safety in operations and economic gains when compared to other alternatives. The proposed system patent has been deposited in Brazil. The economy and safety offered by the monitoring system doesn´t have similarities to the existing methodologies in the international market. However, it will be necessary a test prototype to develop.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81313526","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}
Mohammed Murif Al-Rubaii محمد مريف الربعي, R. Gajbhiye, A. Al-Yami, R. Alouhali
Drilling rate remains a major challenge when it comes to planning and drilling workover and development wells. The main mission of a drilling engineer is to design a well optimizing time, cost, economics and safety. Analysis of previously drilled wells operations' records is required to perform optimization techniques to reduce drilling cost for new wells to be drilled. Among the many potential optimizations, Rate of Penetration (ROP) has the most obvious impact on cost effectiveness of a well's drilling, but to ensure optimized rate of penetration, it must be engineered. There are several correlations, methods, designs, models, tools, charts, fields' results, and experimental studies to enhance the well drilling performance. Many of these are effective, but some others are incomplete and not suited for drilling operations as they are based on unproven theory and lack proper experimental data. Proper models must include knowledge of all factors that affect rate of penetration in order to provide a meaningful tool for optimizing the well design. The objective of this work is to develop a new method for optimized drilling rate that will model rate of penetration more accurately and therefore facilitate improving drilling efficiency and cost. The drilling parameters and mud rheological properties in certain hole sections were collected and analyzed first to determine the effect of mud properties and drilling parameters on ROP performance. The parameters and properties that are selected are from the same hole size, formation type and mud type. The relationship between mud rheological properties and ROP was then evaluated to determine how strong it is. This step helps to determine the significance of mud rheological properties on estimating ROP and that will lead to optimization of the drilling operation and reduction in the drilling time. This is the first model combining the drilling fluid properties, drilling parameters, cuttings volume and dogleg severity with rate of penetration optimization simultaneously. The developed model has been compared with using field data during drilling challenging hole sections in several different fields. It has shown high correlation coefficient regression value matching with actual ROP Values with high percentage of accuracy, which is about 90 %. The new model showed the importance of combining mud properties, cuttings volume percent, drilling parameters and dogleg severity since that will make it applicable in any type of wellbore or hole section such as (vertical, deviated and horizontal). The developed model can assist drilling engineers in selecting improved drilling parameters, mud properties, optimized value of cuttings volume or cuttings concentrations in annulus and dogleg severity value by optimizing the drilling rate using the developed model effectively. It can be used in real time operating center to participate for drilling Automation projects.
{"title":"A New Robust Drilling Rate Model","authors":"Mohammed Murif Al-Rubaii محمد مريف الربعي, R. Gajbhiye, A. Al-Yami, R. Alouhali","doi":"10.4043/29933-ms","DOIUrl":"https://doi.org/10.4043/29933-ms","url":null,"abstract":"\u0000 Drilling rate remains a major challenge when it comes to planning and drilling workover and development wells. The main mission of a drilling engineer is to design a well optimizing time, cost, economics and safety. Analysis of previously drilled wells operations' records is required to perform optimization techniques to reduce drilling cost for new wells to be drilled. Among the many potential optimizations, Rate of Penetration (ROP) has the most obvious impact on cost effectiveness of a well's drilling, but to ensure optimized rate of penetration, it must be engineered.\u0000 There are several correlations, methods, designs, models, tools, charts, fields' results, and experimental studies to enhance the well drilling performance. Many of these are effective, but some others are incomplete and not suited for drilling operations as they are based on unproven theory and lack proper experimental data. Proper models must include knowledge of all factors that affect rate of penetration in order to provide a meaningful tool for optimizing the well design. The objective of this work is to develop a new method for optimized drilling rate that will model rate of penetration more accurately and therefore facilitate improving drilling efficiency and cost.\u0000 The drilling parameters and mud rheological properties in certain hole sections were collected and analyzed first to determine the effect of mud properties and drilling parameters on ROP performance. The parameters and properties that are selected are from the same hole size, formation type and mud type. The relationship between mud rheological properties and ROP was then evaluated to determine how strong it is. This step helps to determine the significance of mud rheological properties on estimating ROP and that will lead to optimization of the drilling operation and reduction in the drilling time. This is the first model combining the drilling fluid properties, drilling parameters, cuttings volume and dogleg severity with rate of penetration optimization simultaneously.\u0000 The developed model has been compared with using field data during drilling challenging hole sections in several different fields. It has shown high correlation coefficient regression value matching with actual ROP Values with high percentage of accuracy, which is about 90 %. The new model showed the importance of combining mud properties, cuttings volume percent, drilling parameters and dogleg severity since that will make it applicable in any type of wellbore or hole section such as (vertical, deviated and horizontal). The developed model can assist drilling engineers in selecting improved drilling parameters, mud properties, optimized value of cuttings volume or cuttings concentrations in annulus and dogleg severity value by optimizing the drilling rate using the developed model effectively. It can be used in real time operating center to participate for drilling Automation projects.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84639277","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}
Santiago Drexler, F. Hoerlle, Thaís M. G. Silveira, Leandro A. Cavadas, P. Couto
Wettability is an important property in reservoir characterization. For the heterogeneous carbonate reservoirs in the Brazilian Pre-Salt, parameters that represent wettability are needed to obtain improved reservoir models. In this work, we applied contact angle measurements to analyze rock-fluid interactions between synthetic brine, crude oil from a Pre-Salt field and rocks and minerals with similar characteristics to the Pre-Salt formations. We studied the effects of aging time on different solid substrates. We found that, even though unaged quartz showed greater interaction with the high basic number oil than carbonates, it re mained water-wet for different aging times. On the other hand, calcite and coquinas had increasing contact angles with aging times and were strongly oil-wet after 30 days aging. This evidences that the interactions between acid compounds in the oil and basic sites in the substrate are strong enough to disrupt the water film after aging for 30 days. Therefore, under the Pre-Salt conditions studied in this work, these carbonate rocks and minerals should be considered as preferentially oil-wet.
{"title":"Impact of Rock Aging Time on the Initial Wettability of Minerals and Analogue Rocks Using Pre-Salt Fluids Under Reservoir Conditions","authors":"Santiago Drexler, F. Hoerlle, Thaís M. G. Silveira, Leandro A. Cavadas, P. Couto","doi":"10.4043/29909-ms","DOIUrl":"https://doi.org/10.4043/29909-ms","url":null,"abstract":"\u0000 Wettability is an important property in reservoir characterization. For the heterogeneous carbonate reservoirs in the Brazilian Pre-Salt, parameters that represent wettability are needed to obtain improved reservoir models. In this work, we applied contact angle measurements to analyze rock-fluid interactions between synthetic brine, crude oil from a Pre-Salt field and rocks and minerals with similar characteristics to the Pre-Salt formations. We studied the effects of aging time on different solid substrates. We found that, even though unaged quartz showed greater interaction with the high basic number oil than carbonates, it re mained water-wet for different aging times. On the other hand, calcite and coquinas had increasing contact angles with aging times and were strongly oil-wet after 30 days aging. This evidences that the interactions between acid compounds in the oil and basic sites in the substrate are strong enough to disrupt the water film after aging for 30 days. Therefore, under the Pre-Salt conditions studied in this work, these carbonate rocks and minerals should be considered as preferentially oil-wet.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85327066","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}
Samba Ba, Dmitry Belov, Daniel Nobre, L. Yin, Eric Johnson
Today, drill bits and mud motor issues often account for more than half of the reasons for pulling out of hole before total depth (TD) on typical directional drilling wells. In this paper, we present a comprehensive methodology designed for optimally matching drill bits, mud motors, and bottomhole assembly (BHA) components for reduced failure risks and improved drilling performance. The methodology consists of combining the design characteristics of drill bits, mud motors, and the rest of the BHA. Each crucial component, like the drill bit, the mud motor, or the rotary steerable system, is analyzed with a particular simulation software made for the component itself before combining the components into a system analysis tool that considers all the detailed features. For example, the simulation software for the mud motor and power section optimizes for the type of elastomer, the mud compatibility, and the fit used. Cutter types and geometries, hydraulics, rocks, and the back and side rake angles are all included in the drill bit simulation. A full drillstring and wellbore simulation takes care of the rest of the components and the link to the top drive. The workflow smartly combines physics-based simulation and data analytics to achieve the necessary level of accuracy with reasonable computation time. The new methodology presented here enables performing joint simulations of performance, durability, and stability for the first time. The performance simulation involved rate of penetration (ROP) prediction, motor power output, and available downhole torque. The durability consists of estimating the motor fatigue life, the bit wear over time, and the fatigue estimation of BHA components. The stability simulation analysis risks of lateral vibration, axial vibration, stick/slip, and bit and BHA whirl. All these are done on a system level with interdependences between different components considered. It enables matching the best bit with the best motor under the best possible BHA. The full workflow was evaluated with the drilling of a typical section in the Permian with significant improvement in both the ROP and reliability. In summary, this paper describes a collective simulation capability that enables matching the bit, motor, and BHA by evaluating the design characteristics of each component and combining them into a system-level simulation tool. It enables joint evaluation of the ROP capability, bit wear, motor fatigue life, and BHA shock and vibration. At the end, we can perform fast drilling without compromising durability or reliability.
{"title":"Combined Data Analytics and Physics-Based Simulation for Optimum Bit, Motor, BHA Combination","authors":"Samba Ba, Dmitry Belov, Daniel Nobre, L. Yin, Eric Johnson","doi":"10.4043/29875-ms","DOIUrl":"https://doi.org/10.4043/29875-ms","url":null,"abstract":"\u0000 Today, drill bits and mud motor issues often account for more than half of the reasons for pulling out of hole before total depth (TD) on typical directional drilling wells. In this paper, we present a comprehensive methodology designed for optimally matching drill bits, mud motors, and bottomhole assembly (BHA) components for reduced failure risks and improved drilling performance.\u0000 The methodology consists of combining the design characteristics of drill bits, mud motors, and the rest of the BHA. Each crucial component, like the drill bit, the mud motor, or the rotary steerable system, is analyzed with a particular simulation software made for the component itself before combining the components into a system analysis tool that considers all the detailed features. For example, the simulation software for the mud motor and power section optimizes for the type of elastomer, the mud compatibility, and the fit used. Cutter types and geometries, hydraulics, rocks, and the back and side rake angles are all included in the drill bit simulation. A full drillstring and wellbore simulation takes care of the rest of the components and the link to the top drive. The workflow smartly combines physics-based simulation and data analytics to achieve the necessary level of accuracy with reasonable computation time.\u0000 The new methodology presented here enables performing joint simulations of performance, durability, and stability for the first time. The performance simulation involved rate of penetration (ROP) prediction, motor power output, and available downhole torque. The durability consists of estimating the motor fatigue life, the bit wear over time, and the fatigue estimation of BHA components. The stability simulation analysis risks of lateral vibration, axial vibration, stick/slip, and bit and BHA whirl. All these are done on a system level with interdependences between different components considered. It enables matching the best bit with the best motor under the best possible BHA. The full workflow was evaluated with the drilling of a typical section in the Permian with significant improvement in both the ROP and reliability.\u0000 In summary, this paper describes a collective simulation capability that enables matching the bit, motor, and BHA by evaluating the design characteristics of each component and combining them into a system-level simulation tool. It enables joint evaluation of the ROP capability, bit wear, motor fatigue life, and BHA shock and vibration. At the end, we can perform fast drilling without compromising durability or reliability.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83635936","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}
Pedro de Almeida Carísio, C.C.P. Carvalho, Marcela de Oliveira Cocchiarale, Lincoln Homero Thomé Ferreira, O. A. Reales, E. Fairbairn, R. D. T. Filho
The self-sensing capability is a well-studied property of carbon nanotubes blended cement pastes intended for civil construction applications. Nevertheless, most of the studies that can be found in the literature were performed at room temperature, natural humidity and atmospheric pressure. It is necessary to understand how down-hole conditions affect the electrical response of this intelligent material to identify its potential application in the oil industry. This paper presents a study on the effect of relative humidity, internal moisture and temperature on the electric properties of self-sensing cement pastes. These pastes were manufactured with class G cement blended with carbon nanotubes and are intended to be used as an intelligent material capable of auto monitoring its internal stresses and deformations during the post-abandonment phase of a well. Carbon nanotubes blended cement pastes were molded in 2.5 × 2.5 × 11.5 cm3 prisms embedded with copper electrodes. The produced samples were exposed to different relative humidity, internal moisture and temperature conditions and their electrical resistivity was measured at each condition by connecting a DC power supply and a multimeter to the embedded electrodes. Relative humidity and temperature was varied in a climate chamber, already internal moisture was varied by saturating and partially drying the material. It was found that the electrical resistivity of the studied pastes is more highly sensible to internal moisture and temperature, while relative humidity had a lower effect under the studied conditions. These results lead to the conclusions that the electrical response of carbon nanotubes blended pastes is highly affected by environmental conditions, and that for oil-well applications it is necessary to develop correction models that allow an accurate measurement of the internal stresses and deformations of the material.
{"title":"Influence of Humidity, Moisture and Temperature on the Electric Properties of Self-Sensing Cement Pastes for Post-Abandonment Well Monitoring","authors":"Pedro de Almeida Carísio, C.C.P. Carvalho, Marcela de Oliveira Cocchiarale, Lincoln Homero Thomé Ferreira, O. A. Reales, E. Fairbairn, R. D. T. Filho","doi":"10.4043/29894-ms","DOIUrl":"https://doi.org/10.4043/29894-ms","url":null,"abstract":"\u0000 The self-sensing capability is a well-studied property of carbon nanotubes blended cement pastes intended for civil construction applications. Nevertheless, most of the studies that can be found in the literature were performed at room temperature, natural humidity and atmospheric pressure. It is necessary to understand how down-hole conditions affect the electrical response of this intelligent material to identify its potential application in the oil industry. This paper presents a study on the effect of relative humidity, internal moisture and temperature on the electric properties of self-sensing cement pastes. These pastes were manufactured with class G cement blended with carbon nanotubes and are intended to be used as an intelligent material capable of auto monitoring its internal stresses and deformations during the post-abandonment phase of a well. Carbon nanotubes blended cement pastes were molded in 2.5 × 2.5 × 11.5 cm3 prisms embedded with copper electrodes. The produced samples were exposed to different relative humidity, internal moisture and temperature conditions and their electrical resistivity was measured at each condition by connecting a DC power supply and a multimeter to the embedded electrodes. Relative humidity and temperature was varied in a climate chamber, already internal moisture was varied by saturating and partially drying the material. It was found that the electrical resistivity of the studied pastes is more highly sensible to internal moisture and temperature, while relative humidity had a lower effect under the studied conditions. These results lead to the conclusions that the electrical response of carbon nanotubes blended pastes is highly affected by environmental conditions, and that for oil-well applications it is necessary to develop correction models that allow an accurate measurement of the internal stresses and deformations of the material.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76502350","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}
Silvia Schaffel, Fernanda Fortes Westin, O. Hernández, E. L. L. Rovere
GHG emissions will create constraints for the oil and gas industry. Meeting world energy needs with lower GHG emissions is its big challenge in the current context of energy transition. The possibility to use renewable power for the energy supply to offshore O&G E&P activities, thus reducing its emissions is discussed in this paper. In Brazil, there are today three E&P environments: onshore, conventional offshore and pre-salt. In conventional offshore, the reuse of fixed platforms as structures for offshore wind development is an opportunity to be assessed. In the pre-salt, as FPSOs demands are energy intensive, the next generation of offshore wind power floating turbines might be employed. This paper presents some examples of trends in using offshore wind power, highlighting the electrification of O&G platforms associated with GHG reduction. We are in the early days of offshore wind power in Brazil and the promising outlook is not for the short-term, but for the Pre-Salt country, in the current context of energy transition, it will become increasingly important to assess and implement the generation of offshore wind power.
{"title":"Replacing Fossil Fuels by Wind Power in Energy Supply to Offshore Oil&Gas Exploration and Production Activities – Possibilities for Brazil","authors":"Silvia Schaffel, Fernanda Fortes Westin, O. Hernández, E. L. L. Rovere","doi":"10.4043/29879-ms","DOIUrl":"https://doi.org/10.4043/29879-ms","url":null,"abstract":"\u0000 GHG emissions will create constraints for the oil and gas industry. Meeting world energy needs with lower GHG emissions is its big challenge in the current context of energy transition. The possibility to use renewable power for the energy supply to offshore O&G E&P activities, thus reducing its emissions is discussed in this paper. In Brazil, there are today three E&P environments: onshore, conventional offshore and pre-salt. In conventional offshore, the reuse of fixed platforms as structures for offshore wind development is an opportunity to be assessed. In the pre-salt, as FPSOs demands are energy intensive, the next generation of offshore wind power floating turbines might be employed. This paper presents some examples of trends in using offshore wind power, highlighting the electrification of O&G platforms associated with GHG reduction. We are in the early days of offshore wind power in Brazil and the promising outlook is not for the short-term, but for the Pre-Salt country, in the current context of energy transition, it will become increasingly important to assess and implement the generation of offshore wind power.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79167741","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 industry study published by the Independent Project Analysis group in 2012 reported that 78% of upstream projects in 2011 faced either cost or schedule overruns (Merrow, 2012). A similar report, published by EY in 2014, found 64% of projects faced cost overruns and 73% of projects faced schedule overruns (EY, 2014). Similarly, in 2017, the UK Oil & Gas Authority (OGA) published a study of lessons learned from UKCS oil & gas projects between 2011-2016, which reported "since 2011 fewer than 25% of oil and gas projects have been delivered on time with projects averaging 10 months' delay and coming in around 35% over budget." (OGA, 2017) This level of cost and schedule underperformance was not sustainable in the high oil price economic environment and is inconceivable in the lower oil price environment in which we now operate. We cannot continue to make the same mistakes, the need to learn is no more critical than in the deepwater arena: Wood McKenzie report the cost of developing a deepwater project has fallen by more than 50% since 2013 (Offshore, 2018), the increased investment in deepwater is likely to drive an upturn in cyclical costs meaning developments become increasingly marginal and unable to sustain overruns or delays and remain economic.
{"title":"Starting with the End in Mind: More Certain Field Development","authors":"D. McLachlan, J. Isherwood, Max Peile","doi":"10.4043/29804-ms","DOIUrl":"https://doi.org/10.4043/29804-ms","url":null,"abstract":"\u0000 An industry study published by the Independent Project Analysis group in 2012 reported that 78% of upstream projects in 2011 faced either cost or schedule overruns (Merrow, 2012). A similar report, published by EY in 2014, found 64% of projects faced cost overruns and 73% of projects faced schedule overruns (EY, 2014). Similarly, in 2017, the UK Oil & Gas Authority (OGA) published a study of lessons learned from UKCS oil & gas projects between 2011-2016, which reported \"since 2011 fewer than 25% of oil and gas projects have been delivered on time with projects averaging 10 months' delay and coming in around 35% over budget.\" (OGA, 2017) This level of cost and schedule underperformance was not sustainable in the high oil price economic environment and is inconceivable in the lower oil price environment in which we now operate. We cannot continue to make the same mistakes, the need to learn is no more critical than in the deepwater arena: Wood McKenzie report the cost of developing a deepwater project has fallen by more than 50% since 2013 (Offshore, 2018), the increased investment in deepwater is likely to drive an upturn in cyclical costs meaning developments become increasingly marginal and unable to sustain overruns or delays and remain economic.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74919683","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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