K. Mukati, O. Wilson, M. Morales, Brian J. Arias, C. Terry
An integrated multiphase flow well and electrical submersible pump model was used to optimize operating procedures for initial well clean-up and ramp up to production for a major deepwater production system before first oil. An integrated modeling approach was crucial to create and test start-up scenarios given uncertainty in the amount of completion fluid in tubing, uncertainty in density of near wellbore fluid and lack of prior experience in ESP operation. The model was used to simulate numerous well start-up scenarios:Well BS&W rate profiles as a function of frac pack fluid recovery percentageWell unloading profiles as a function of injected base volumeNatural flowing well start-up profilesChemical injection volumes and associated surface injection pressuresPressure surging across the completion during ESP start-upsNumber of "A" annulus bleeds required during initial start-up Accurately simulating such highly transient scenarios requires integrating multiphase flow phenomena in tubing to reservoir inflow and dynamic pump behavior. The integrated model proved to be very valuable in finalizing well start-up procedure with a high degree of confidence. This fully dynamic model can estimate phase, pressure, temperature and flow anywhere in the tubing including effect of well choke operations, pump pressure and temperature dynamics based on speed, effect of downhole conditions, and reservoir inflow. The transient behavior in tubing and annulus upon switching on or off ESP pump during well operation is also accurately represented. In this paper, we will present how the integrated model was developed, how it was used to simulate various scenarios and how the results were used to create and validate well start-up procedure. The methodology presented here is applicable to any well using ESP artificial lift methods. This model is a very useful tool not only for engineering simulation, but for operator training and real-time surveillance as well.
{"title":"Optimization of Well Start-Up Using Integrated Well and Electrical Submersible Pump Modeling","authors":"K. Mukati, O. Wilson, M. Morales, Brian J. Arias, C. Terry","doi":"10.4043/29354-MS","DOIUrl":"https://doi.org/10.4043/29354-MS","url":null,"abstract":"\u0000 An integrated multiphase flow well and electrical submersible pump model was used to optimize operating procedures for initial well clean-up and ramp up to production for a major deepwater production system before first oil. An integrated modeling approach was crucial to create and test start-up scenarios given uncertainty in the amount of completion fluid in tubing, uncertainty in density of near wellbore fluid and lack of prior experience in ESP operation.\u0000 The model was used to simulate numerous well start-up scenarios:Well BS&W rate profiles as a function of frac pack fluid recovery percentageWell unloading profiles as a function of injected base volumeNatural flowing well start-up profilesChemical injection volumes and associated surface injection pressuresPressure surging across the completion during ESP start-upsNumber of \"A\" annulus bleeds required during initial start-up\u0000 Accurately simulating such highly transient scenarios requires integrating multiphase flow phenomena in tubing to reservoir inflow and dynamic pump behavior. The integrated model proved to be very valuable in finalizing well start-up procedure with a high degree of confidence. This fully dynamic model can estimate phase, pressure, temperature and flow anywhere in the tubing including effect of well choke operations, pump pressure and temperature dynamics based on speed, effect of downhole conditions, and reservoir inflow. The transient behavior in tubing and annulus upon switching on or off ESP pump during well operation is also accurately represented.\u0000 In this paper, we will present how the integrated model was developed, how it was used to simulate various scenarios and how the results were used to create and validate well start-up procedure. The methodology presented here is applicable to any well using ESP artificial lift methods. This model is a very useful tool not only for engineering simulation, but for operator training and real-time surveillance as well.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73116917","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 Advanced Technology Lab has developed a Fire Test Facility that became operational in spring 2015. This paper describes a fresh approach to the systems engineering process path taken during development to capture new capabilities and opportunities for such a system. New functions and safety features are discussed, as compared to the original system that was replaced. Recent fire incidents on offshore rigs have increased interest in meeting rigorous standards for fire safety. As a result of a needs assessment, a replacement Fire Test Facility (FTF) was developed in order to test offshore equipment. Offshore valves and connectors on rigs must be certified to withstand sustained fire conditions per American Petroleum Institute (API) standards 6FA/B/C. The requirements include surviving fire temperatures up to 1800 F for a period of 30 minutes, while holding internal pressure and even withstanding bending loads. Updated safety regulations at the company led to a review of the original Fire Test Facility, and it was determined that a new system was necessary to incorporate blast protection, controls automation, and situational awareness. After establishing needs and goals from our internal customer, derived requirements were generated. Using the company’s system engineering "engine", this led to a design that met customer requirements and enhanced safety. Improvements over the original system include a 6-sided bunker structure, passive ventilation, gas safety purges, remote operation to keep workers outside the hot zone, and real-time charting to assess test performance. After integration of the facility, a verification matrix was used to assess system functionality and performance. The improved system allows for quicker test turnaround, and more refined burn tests at reduced costs compared to using external test facilities. Mock fire tests can be performed to assess "what-if" conditions prior to actual testing of equipment. Several tests were successfully performed to API standards. Results and observations throughout the systems engineering process, including systems integration and checkout of the Fire Test Facility are provided.
{"title":"Fire Test Facility for Offshore Field Equipment - Success Achieved with Systems Engineering Practice","authors":"Matthew Johnson","doi":"10.4043/29359-MS","DOIUrl":"https://doi.org/10.4043/29359-MS","url":null,"abstract":"\u0000 The Advanced Technology Lab has developed a Fire Test Facility that became operational in spring 2015. This paper describes a fresh approach to the systems engineering process path taken during development to capture new capabilities and opportunities for such a system. New functions and safety features are discussed, as compared to the original system that was replaced.\u0000 Recent fire incidents on offshore rigs have increased interest in meeting rigorous standards for fire safety. As a result of a needs assessment, a replacement Fire Test Facility (FTF) was developed in order to test offshore equipment. Offshore valves and connectors on rigs must be certified to withstand sustained fire conditions per American Petroleum Institute (API) standards 6FA/B/C. The requirements include surviving fire temperatures up to 1800 F for a period of 30 minutes, while holding internal pressure and even withstanding bending loads.\u0000 Updated safety regulations at the company led to a review of the original Fire Test Facility, and it was determined that a new system was necessary to incorporate blast protection, controls automation, and situational awareness. After establishing needs and goals from our internal customer, derived requirements were generated. Using the company’s system engineering \"engine\", this led to a design that met customer requirements and enhanced safety. Improvements over the original system include a 6-sided bunker structure, passive ventilation, gas safety purges, remote operation to keep workers outside the hot zone, and real-time charting to assess test performance.\u0000 After integration of the facility, a verification matrix was used to assess system functionality and performance. The improved system allows for quicker test turnaround, and more refined burn tests at reduced costs compared to using external test facilities. Mock fire tests can be performed to assess \"what-if\" conditions prior to actual testing of equipment. Several tests were successfully performed to API standards. Results and observations throughout the systems engineering process, including systems integration and checkout of the Fire Test Facility are provided.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81631077","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}
Proppant such as sand and ceramics is used in keeping the fractures open for hydrocarbon production in hydraulic fracturing operations. Its ability to withstand reservoir closure stresses and provide high conductivity is one of its key selection criteria. Sand is preferred over ceramics in unconventional plays due to its low cost and abundance. On the other hand, the lower crush strength of sand compared to ceramics limits its application to wells having lower closure stresses. Therefore, it becomes necessary to strengthen the sand as a low cost solution for demanding downhole conditions. Coating sand with resin is a long-practiced method to strengthen and control fines. One fundamental challenge with resin coated sand (RCS) lies in its overall thermo-chemo-mechanical stability at high temperature and high pressure in the presence of fracturing fluid. In this work, a nanocomposite resin has been developed to provide enhanced coating strength and chemical stability. RCS has been characterized from the perspectives of its core and coating. As received sand has been evaluated by (1) single grain crush testing, (2) optical particle size analysis for sphericity and roundness, (3) XRD for mineral content and composition, and (4) petrography analysis for microstructure, texture, and crystalline phases. Sand has been coated using phenolic formaldehyde (novolac) resin systems reinforced with nanomaterials and altered surface wetting properties demonstrating improved crush strength, chemical resistance and long-term conductivity. Loss on ignition (LOI), API proppant crush resistance test, and API long-term proppant conductivity tests have been used to evaluate RCS. Petrographic evaluation of Northern white sand shows the presence of plutonic, and monocrystalline grains having higher crush strength, whereas Texas brown sand shows abundance of polycrystalline and metamorphic grains that are relatively weaker due to impurities, and inner weak planes. The white sands are well sorted and a roundness and sphericity of >0.6 were measured by optical particle size analysis. With resin coating, the API crush resistance stress of the sand has increased by ∼200%; whereas, the API long-term proppant conductivity has increased by 41% compared to uncoated sand. The nano-composite resin coating containing a combination of nano-reinforcement materials and wettability altering agents has increased the API proppant conductivity further by 100% compared to uncoated sand. Nanomaterial used in the coating contains high surface area nanofibers with exceptionally high aspect ratio. The synergistic effect of different nanoparticles increased the strength to an even higher level by providing a barrier to the permeation of fluid in the coating thereby increasing chemical resistance. An economic and up-scalable nano-composite coating technology containing a novel combination of nanomaterials and surface wettability altering agents has been developed with improved proppant crush
{"title":"Nano-Composite Resin Coated Proppant for Hydraulic Fracturing","authors":"M. Haque, Saini Rajesh Kumar, M. Sayed","doi":"10.4043/29572-MS","DOIUrl":"https://doi.org/10.4043/29572-MS","url":null,"abstract":"\u0000 Proppant such as sand and ceramics is used in keeping the fractures open for hydrocarbon production in hydraulic fracturing operations. Its ability to withstand reservoir closure stresses and provide high conductivity is one of its key selection criteria. Sand is preferred over ceramics in unconventional plays due to its low cost and abundance. On the other hand, the lower crush strength of sand compared to ceramics limits its application to wells having lower closure stresses. Therefore, it becomes necessary to strengthen the sand as a low cost solution for demanding downhole conditions. Coating sand with resin is a long-practiced method to strengthen and control fines. One fundamental challenge with resin coated sand (RCS) lies in its overall thermo-chemo-mechanical stability at high temperature and high pressure in the presence of fracturing fluid.\u0000 In this work, a nanocomposite resin has been developed to provide enhanced coating strength and chemical stability. RCS has been characterized from the perspectives of its core and coating. As received sand has been evaluated by (1) single grain crush testing, (2) optical particle size analysis for sphericity and roundness, (3) XRD for mineral content and composition, and (4) petrography analysis for microstructure, texture, and crystalline phases. Sand has been coated using phenolic formaldehyde (novolac) resin systems reinforced with nanomaterials and altered surface wetting properties demonstrating improved crush strength, chemical resistance and long-term conductivity. Loss on ignition (LOI), API proppant crush resistance test, and API long-term proppant conductivity tests have been used to evaluate RCS.\u0000 Petrographic evaluation of Northern white sand shows the presence of plutonic, and monocrystalline grains having higher crush strength, whereas Texas brown sand shows abundance of polycrystalline and metamorphic grains that are relatively weaker due to impurities, and inner weak planes. The white sands are well sorted and a roundness and sphericity of >0.6 were measured by optical particle size analysis. With resin coating, the API crush resistance stress of the sand has increased by ∼200%; whereas, the API long-term proppant conductivity has increased by 41% compared to uncoated sand. The nano-composite resin coating containing a combination of nano-reinforcement materials and wettability altering agents has increased the API proppant conductivity further by 100% compared to uncoated sand. Nanomaterial used in the coating contains high surface area nanofibers with exceptionally high aspect ratio. The synergistic effect of different nanoparticles increased the strength to an even higher level by providing a barrier to the permeation of fluid in the coating thereby increasing chemical resistance.\u0000 An economic and up-scalable nano-composite coating technology containing a novel combination of nanomaterials and surface wettability altering agents has been developed with improved proppant crush ","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83300514","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}
Marcus P. Heydrich, A. Hammami, Suresh Choudhary, Marcos Mockel, J. Ratulowski
The deposition and growth of scale on the internal surface of oil & gas pipelines is a major challenge in the operation and maintenance of these lines. Pigging and chemical treatment are currently available solutions, but these are expensive, and a permanent passive alternative would be preferable. Diamond Like Coatings (DLC) have shown considerable promise, but the industry remains skeptical in the absence of conclusive evidence. This work addresses the question for a novel super hydrophobic DLC with a parametric evaluation of factors affecting adhesion and growth of common scale groups (such as Calcites and Barites) including surface finish of the substrate, metal composition, and thickness (or presence) of the coating, as well as the differing mechanisms of scale growth where applicable. The approach involves controlled deposition of inorganic scales onto rotational cylindrical electrodes (RCE) under varying conditions of temperature, solution chemistry, flow rates, followed by submerged jet impingement to quantify the corresponding deposit bond strengths and failure modes (cohesion vs. adhesion). Design of Experiments (DOE) methods are used to set and analyze the contribution of deposition and matrix factors simultaneously.
油气管道内表面水垢的沉积和生长是油气管道运行和维护的主要挑战。目前，清管和化学处理都是可行的解决方案，但这些方法都很昂贵，而且永久性的被动替代方案更可取。类金刚石涂层(Diamond Like Coatings, DLC)已经显示出相当大的前景，但由于缺乏确凿的证据，该行业仍持怀疑态度。这项工作解决了一种新型超疏水DLC的问题，通过参数化评估影响常见水垢基团(如方解石和重晶石)的粘附和生长的因素，包括基材的表面光洁度、金属成分和涂层的厚度(或存在)，以及适用的水垢生长的不同机制。该方法包括在不同的温度、溶液化学、流速条件下，控制无机垢在旋转圆柱形电极(RCE)上的沉积，然后通过水下射流撞击来量化相应的沉积结合强度和破坏模式(内聚与粘附)。采用实验设计(DOE)方法同时设定和分析沉积和基质因素的贡献。
{"title":"Impact of a Novel Coating on Inorganic Scale Deposit Growth and Adhesion","authors":"Marcus P. Heydrich, A. Hammami, Suresh Choudhary, Marcos Mockel, J. Ratulowski","doi":"10.4043/29218-MS","DOIUrl":"https://doi.org/10.4043/29218-MS","url":null,"abstract":"\u0000 The deposition and growth of scale on the internal surface of oil & gas pipelines is a major challenge in the operation and maintenance of these lines. Pigging and chemical treatment are currently available solutions, but these are expensive, and a permanent passive alternative would be preferable. Diamond Like Coatings (DLC) have shown considerable promise, but the industry remains skeptical in the absence of conclusive evidence. This work addresses the question for a novel super hydrophobic DLC with a parametric evaluation of factors affecting adhesion and growth of common scale groups (such as Calcites and Barites) including surface finish of the substrate, metal composition, and thickness (or presence) of the coating, as well as the differing mechanisms of scale growth where applicable. The approach involves controlled deposition of inorganic scales onto rotational cylindrical electrodes (RCE) under varying conditions of temperature, solution chemistry, flow rates, followed by submerged jet impingement to quantify the corresponding deposit bond strengths and failure modes (cohesion vs. adhesion). Design of Experiments (DOE) methods are used to set and analyze the contribution of deposition and matrix factors simultaneously.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"365 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82522181","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}
Yan Wang, L. M. Rivero, T. Palermo, C. Koh, L. Zerpa
Current oil prices have shifted the offshore flow assurance philosophy from "hydrate avoidance" to "hydrate management". In order to manage hydrate formation in the pipeline, not only do we need to have a good understanding of the hydrate formation process, but also a comprehensive hydrate formation predictive tool is necessary. In this work, a transient hydrate simulation tool coupled with a multiphase flow simulator, which predicts the hydrate formation rate and amount to determine hydrate slurry transportability, is applied to assess the hydrate formation risk in an offshore gas condensate subsea tieback under design stage. A simulation model is developed using the geometry, fluid properties and predicted production data from this field. This gas condensate field has an offshore separator that connects to a subsea production line. After separation, gas and liquids are transported by export lines. In this study, the hydrate formation in the production and the liquid export lines was estimated using the transient hydrate simulation tool. Simulation studies were performed to assess the hydrate plugging risk at both steady state and transient operations considering different water cuts. This simulation tool has been demonstrated to be useful in modeling hydrate management during subsea pipeline design and optimization, and can provide guidelines for safe and cost-effective hydrate management in the field.
{"title":"Assessing Hydrate Formation in a Gas Condensate Subsea Tieback Using a Transient Hydrate Simulation Tool","authors":"Yan Wang, L. M. Rivero, T. Palermo, C. Koh, L. Zerpa","doi":"10.4043/29280-MS","DOIUrl":"https://doi.org/10.4043/29280-MS","url":null,"abstract":"\u0000 Current oil prices have shifted the offshore flow assurance philosophy from \"hydrate avoidance\" to \"hydrate management\". In order to manage hydrate formation in the pipeline, not only do we need to have a good understanding of the hydrate formation process, but also a comprehensive hydrate formation predictive tool is necessary. In this work, a transient hydrate simulation tool coupled with a multiphase flow simulator, which predicts the hydrate formation rate and amount to determine hydrate slurry transportability, is applied to assess the hydrate formation risk in an offshore gas condensate subsea tieback under design stage. A simulation model is developed using the geometry, fluid properties and predicted production data from this field. This gas condensate field has an offshore separator that connects to a subsea production line. After separation, gas and liquids are transported by export lines. In this study, the hydrate formation in the production and the liquid export lines was estimated using the transient hydrate simulation tool. Simulation studies were performed to assess the hydrate plugging risk at both steady state and transient operations considering different water cuts. This simulation tool has been demonstrated to be useful in modeling hydrate management during subsea pipeline design and optimization, and can provide guidelines for safe and cost-effective hydrate management in the field.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"73 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83359751","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}
G. O. Wilson, S. Kasisomayajula, Christopher R Dayton, Aidnel G. Navarro
In a 2016 NACE report, the global cost of corrosion was estimated to be about US$ 2.5 trillion, which amounts to about 3.4% of global Gross Domestic Product (GDP). Industries such as oil and gas that maintain a disproportionate amount of their assets in extremely corrosive environments bear a disproportionate amount of these costs. Add to these costs the environmental and individual safety consequences of material failure due to corrosion and the case for investing in new technologies geared towards improving corrosion protection can hardly be overstated. In this paper, we report on novel additives which leverage the incorporation of microencapsulated healing agents into coating systems with a view towards lengthening their service lives and that of their underlying substrates while minimizing the opportunity cost of downtime associated with maintenance. These self-healing additives have been evaluated in a broad range of coating systems selected to provide the asset owner/operator with a range of options aimed at delivering improved readiness and cost savings across the oil and gas value chain. Here, we provide an overview of evaluations performed in in a range of coating chemistries. For all the data reported, the efficacy of the self-healing additives was evaluated by incorporation into a coating system and comparing relative to the equivalent commercially available coating. For all the comparisons, the control and the self-healing versions of the coating were damaged by scribing followed by equilibration at room temperature for a minimum of 24 h prior to accelerated corrosion testing. A summary of the performance improvements observed upon incorporation of the self-healing additive into coating formulations is provided in Figure 1.
{"title":"Self-Healing Functionality in the Protection of Off-Shore Oil and Gas Assets","authors":"G. O. Wilson, S. Kasisomayajula, Christopher R Dayton, Aidnel G. Navarro","doi":"10.4043/29383-MS","DOIUrl":"https://doi.org/10.4043/29383-MS","url":null,"abstract":"\u0000 In a 2016 NACE report, the global cost of corrosion was estimated to be about US$ 2.5 trillion, which amounts to about 3.4% of global Gross Domestic Product (GDP). Industries such as oil and gas that maintain a disproportionate amount of their assets in extremely corrosive environments bear a disproportionate amount of these costs. Add to these costs the environmental and individual safety consequences of material failure due to corrosion and the case for investing in new technologies geared towards improving corrosion protection can hardly be overstated. In this paper, we report on novel additives which leverage the incorporation of microencapsulated healing agents into coating systems with a view towards lengthening their service lives and that of their underlying substrates while minimizing the opportunity cost of downtime associated with maintenance. These self-healing additives have been evaluated in a broad range of coating systems selected to provide the asset owner/operator with a range of options aimed at delivering improved readiness and cost savings across the oil and gas value chain.\u0000 Here, we provide an overview of evaluations performed in in a range of coating chemistries. For all the data reported, the efficacy of the self-healing additives was evaluated by incorporation into a coating system and comparing relative to the equivalent commercially available coating. For all the comparisons, the control and the self-healing versions of the coating were damaged by scribing followed by equilibration at room temperature for a minimum of 24 h prior to accelerated corrosion testing.\u0000 A summary of the performance improvements observed upon incorporation of the self-healing additive into coating formulations is provided in Figure 1.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"64 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85897625","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 show how dynamic machine learning modeling can help drillers and operators validate signals from their sensors. Data and signal quality are a big problem in the industry when it comes to digitization. The method will show the importance of having a validation pipeline, and how it can help other algorithms make better decisions. Our approach uses statistical principles, machine learning and advanced analytics. The method is ISO 8000 compliant and can provide a framework in data management and data quality for companies to use. Depending on the application the accuracy of our method will vary. Results are anywhere in the 88% - 99% range of accuracy. The process has been validated by a major drilling contractor in signals ranging from blow out prevention, dynamic positioning systems, and tripping. The process can save upwards of 50% of time spent cleaning, mapping, and validating sensor signals. The end product allows the user to understand problems in the data collection system from the sensor all the way to the enterprise historian. It will also reduce false positives and false negative that are present in maintenance, optimization, and automation.
{"title":"Machine Learning Validation of Time Series Signals to Reduce Mistakes in Digital Algorithms for Maintenance, Optimization, and Automation","authors":"Gustavo Sánchez","doi":"10.4043/29217-MS","DOIUrl":"https://doi.org/10.4043/29217-MS","url":null,"abstract":"\u0000 The objective of the paper is to show how dynamic machine learning modeling can help drillers and operators validate signals from their sensors. Data and signal quality are a big problem in the industry when it comes to digitization. The method will show the importance of having a validation pipeline, and how it can help other algorithms make better decisions. Our approach uses statistical principles, machine learning and advanced analytics. The method is ISO 8000 compliant and can provide a framework in data management and data quality for companies to use. Depending on the application the accuracy of our method will vary. Results are anywhere in the 88% - 99% range of accuracy. The process has been validated by a major drilling contractor in signals ranging from blow out prevention, dynamic positioning systems, and tripping. The process can save upwards of 50% of time spent cleaning, mapping, and validating sensor signals. The end product allows the user to understand problems in the data collection system from the sensor all the way to the enterprise historian. It will also reduce false positives and false negative that are present in maintenance, optimization, and automation.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87424579","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}
Performance of anti-agglomerants (AAs) depends on many factors, including salinity, water cut (WC), characteristics of the hydrocarbons, gas composition, reservoir conditions, production system conditions, and especially AA stability at the application conditions. Most AAs are surfactants, with one or multiple long hydrophobic tails and a charged hydrophilic head. This class of chemistry is often not easily degraded in the environment and can, therefore, be eliminated from consideration for application in environmentally sensitive regions. This paper presents the development of an AA that can be applied under a wide range of production conditions and is unique because of its ready biodegradability [>60% compared to other AAs, which either are not biodegradable (<20%) or can only achieve inherent biodegradability of 20 to 60%]. Rocking cell testing was conducted to determine the performance boundaries of the AA chemistry. Light, medium, and dark oils from various fields were used to evaluate the performance of the AA in aqueous phases ranging from condensed water (effectively, 0% salinity) to high salinity (~12%). Test results were categorized as "pass" for transportable hydrate slurries and "fail" if the systems plugged, and/or showed large hydrate crystals, and/or resulted in high slurry viscosity. Visual observations throughout the test and proximity sensor data provided qualitative and quantitative representations of the behavior of fluids in each cell. Water quality and emulsion tendency testing were conducted to verify that the AA would be suitable for offshore use and operable at topside. Biodegradation testing of the AA was conducted in seawater according to OECD 306 (1992). Systematic study demonstrated strong versatility for application of this AA to help prevent hydrate blockages in pipelines. Optimizing the head and tail length of the molecule was crucial for allowing it to treat a wide range of salinities, WCs, and oils with different API gravities. No sign of hydrate blockage was observed when applying the designed AA at minimum effective dosage (MED). The optimized product demonstrates overboard oil and water quality, thereby eliminating the need for an emulsion breaker and/or a water clarifier. The presented AA has a ready biodegradability of 61.8% [greater than 60% is categorized as readily biodegradable using OECD 306 (1992) methodology] and has been successfully implemented to treat hydrate plugging in the Gulf of Mexico (GOM).
{"title":"Biodegradable Anti-Agglomerant Chemistry for Hydrate Plug Prevention in Various Production Conditions","authors":"D. Monteiro, L. Vo, Prince Philippe, S. Bodnar","doi":"10.4043/29660-MS","DOIUrl":"https://doi.org/10.4043/29660-MS","url":null,"abstract":"\u0000 Performance of anti-agglomerants (AAs) depends on many factors, including salinity, water cut (WC), characteristics of the hydrocarbons, gas composition, reservoir conditions, production system conditions, and especially AA stability at the application conditions. Most AAs are surfactants, with one or multiple long hydrophobic tails and a charged hydrophilic head. This class of chemistry is often not easily degraded in the environment and can, therefore, be eliminated from consideration for application in environmentally sensitive regions. This paper presents the development of an AA that can be applied under a wide range of production conditions and is unique because of its ready biodegradability [>60% compared to other AAs, which either are not biodegradable (<20%) or can only achieve inherent biodegradability of 20 to 60%].\u0000 Rocking cell testing was conducted to determine the performance boundaries of the AA chemistry. Light, medium, and dark oils from various fields were used to evaluate the performance of the AA in aqueous phases ranging from condensed water (effectively, 0% salinity) to high salinity (~12%). Test results were categorized as \"pass\" for transportable hydrate slurries and \"fail\" if the systems plugged, and/or showed large hydrate crystals, and/or resulted in high slurry viscosity. Visual observations throughout the test and proximity sensor data provided qualitative and quantitative representations of the behavior of fluids in each cell. Water quality and emulsion tendency testing were conducted to verify that the AA would be suitable for offshore use and operable at topside. Biodegradation testing of the AA was conducted in seawater according to OECD 306 (1992).\u0000 Systematic study demonstrated strong versatility for application of this AA to help prevent hydrate blockages in pipelines. Optimizing the head and tail length of the molecule was crucial for allowing it to treat a wide range of salinities, WCs, and oils with different API gravities. No sign of hydrate blockage was observed when applying the designed AA at minimum effective dosage (MED). The optimized product demonstrates overboard oil and water quality, thereby eliminating the need for an emulsion breaker and/or a water clarifier. The presented AA has a ready biodegradability of 61.8% [greater than 60% is categorized as readily biodegradable using OECD 306 (1992) methodology] and has been successfully implemented to treat hydrate plugging in the Gulf of Mexico (GOM).","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"64 11","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91423467","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}
Technology gaps in measuring wellbore parameters and providing the results at surface without using wireline (Production Logging) or slick-line, without using mud-pulse, electromagnetic or acoustic telemetry, or pre-installed or permanently installed downhole sensors remain an area to be bridged. Our ability to engineer light-weight, high-strength, highly-reactive (dissolvable) or corrosion-resistant, nanostructured-alloys and intelligent micro-electromechanical system (MEMS) devices have enabled design of buoyant sensors having thin (millimetric) wall, capable of withstanding 20,000 psi or more differential pressure. These sensors measure and record a complete set of the client’s required wellbore parameters (e.g., Pressure, Temperature, Depth, Casing collars, Flow-rate across perforations or in wellbore, Water cut, Dissolved O2, etc.). These devices are deployed, either nested in an outer shell of salinity independent water reactive alloy to abet pump down to depth or weighed down by a sinker of dissolvable alloy. These devices are free-flowing within a wellbore so that they can be placed downhole to required depth for a specific time, after which the outer shell dissolves or the sinker weight falls, releasing the inner gauge. The now buoyant device flows back to surface with produced fluids where they make their presence known by sonic or inductive signaling. Our company was founded to take advantage of these disruptive innovations in materials science and sensors and synthesis of these technologies to provide superior performance products for both deep-water domains and the multistage stimulation (MSS) market. In this article we address two of our key inventions. First, the development of miniature, self-contained, battery powered, free-flowing sensor devices for reservoir monitoring, passively retrievable through carrier buoyancy. A subset of this game changing approach, to economize operations is, "Measuring in- situ pressure, temperature, and subsequent production during MSS". Second, we present a mechanism to assess susceptibility of oilfield alloys, especially in live reservoir fluids at the production zone. This encompasses a retrievable sensor device to assess environmental effects on materials at target zone in wellbore during production or shut in, can be deployed anywhere from production zone to bubble point, to surface separator. It facilitates testing not in a simulated autoclave environment at surface, but downhole, at the zone of interest.
{"title":"Synthesis of Disruptive Technologies Leads to Design of Flowable Sensors for Reservoir Monitoring, Passively Retrievable Through Carrier Buoyancy","authors":"Ting Chen, R. Shenoy, Indranil Roy, Jing Zhou","doi":"10.4043/29599-MS","DOIUrl":"https://doi.org/10.4043/29599-MS","url":null,"abstract":"\u0000 Technology gaps in measuring wellbore parameters and providing the results at surface without using wireline (Production Logging) or slick-line, without using mud-pulse, electromagnetic or acoustic telemetry, or pre-installed or permanently installed downhole sensors remain an area to be bridged.\u0000 Our ability to engineer light-weight, high-strength, highly-reactive (dissolvable) or corrosion-resistant, nanostructured-alloys and intelligent micro-electromechanical system (MEMS) devices have enabled design of buoyant sensors having thin (millimetric) wall, capable of withstanding 20,000 psi or more differential pressure. These sensors measure and record a complete set of the client’s required wellbore parameters (e.g., Pressure, Temperature, Depth, Casing collars, Flow-rate across perforations or in wellbore, Water cut, Dissolved O2, etc.). These devices are deployed, either nested in an outer shell of salinity independent water reactive alloy to abet pump down to depth or weighed down by a sinker of dissolvable alloy. These devices are free-flowing within a wellbore so that they can be placed downhole to required depth for a specific time, after which the outer shell dissolves or the sinker weight falls, releasing the inner gauge. The now buoyant device flows back to surface with produced fluids where they make their presence known by sonic or inductive signaling.\u0000 Our company was founded to take advantage of these disruptive innovations in materials science and sensors and synthesis of these technologies to provide superior performance products for both deep-water domains and the multistage stimulation (MSS) market.\u0000 In this article we address two of our key inventions. First, the development of miniature, self-contained, battery powered, free-flowing sensor devices for reservoir monitoring, passively retrievable through carrier buoyancy. A subset of this game changing approach, to economize operations is, \"Measuring in- situ pressure, temperature, and subsequent production during MSS\". Second, we present a mechanism to assess susceptibility of oilfield alloys, especially in live reservoir fluids at the production zone. This encompasses a retrievable sensor device to assess environmental effects on materials at target zone in wellbore during production or shut in, can be deployed anywhere from production zone to bubble point, to surface separator. It facilitates testing not in a simulated autoclave environment at surface, but downhole, at the zone of interest.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91428974","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}
Shallow water flow (SWF) is a common type of geological hazard in deep-water drilling. It usually occurs in a relatively shallow stratum below mud line (about 450-2500m). When encroached by a drill bit, the substantially over-pressured sand body can generate SWF that may dramatically impair the integrity of the drill string and the associated equipment. However, the mechanism that triggers SWF is lack of detailed understanding, leaving a safe design of drilling through SWF prone strata in suspense. In this paper, through the independent design and development of the shallow water flow simulation device, the damage, and flow mechanism of the sandstone occurred during the SWF events. It can be found through the experiment that in the occurrence of shallow water flow event, there is much sand accumulation around the pressure relief port. The sand body below the pressure relief port is lifted upwards as a whole, and the sand layer above the pressure relief port has a specific amplitude decrease. The findings could not only help understand the SWF process but also build a foundation for subsequent research on prevention and control of SWF incident. In addition, it provides theoretical guidance for improving drilling equipment to ensure that the SWF hazard is adequately controlled.
{"title":"Experimental Investigation on Generation and Development of Shallow Water Flow in Overpressured Sand Formation","authors":"Can Shi, B. Lin, Yan Jin, Jun Shentu","doi":"10.4043/29416-MS","DOIUrl":"https://doi.org/10.4043/29416-MS","url":null,"abstract":"\u0000 Shallow water flow (SWF) is a common type of geological hazard in deep-water drilling. It usually occurs in a relatively shallow stratum below mud line (about 450-2500m). When encroached by a drill bit, the substantially over-pressured sand body can generate SWF that may dramatically impair the integrity of the drill string and the associated equipment. However, the mechanism that triggers SWF is lack of detailed understanding, leaving a safe design of drilling through SWF prone strata in suspense. In this paper, through the independent design and development of the shallow water flow simulation device, the damage, and flow mechanism of the sandstone occurred during the SWF events. It can be found through the experiment that in the occurrence of shallow water flow event, there is much sand accumulation around the pressure relief port. The sand body below the pressure relief port is lifted upwards as a whole, and the sand layer above the pressure relief port has a specific amplitude decrease. The findings could not only help understand the SWF process but also build a foundation for subsequent research on prevention and control of SWF incident. In addition, it provides theoretical guidance for improving drilling equipment to ensure that the SWF hazard is adequately controlled.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90424477","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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