Oil and gas companies have shifted their investment priorities to low CAPEX brownfield projects in response to historically low oil and gas prices. One approach is to increase the production by drilling new wells and tying them back to existing tripods. However, existing tripods have limited as-built design data and are usually near the allowable structural capacity limits. This study introduces a novel concept of the "hybrid conductor-supported tripod" to support the new wellheads. This approach minimizes the need to modify the existing tripods. The hybrid conductor-supported tripod utilizes the new well conductors to support the wellheads, extends to the existing tripod topside to support the production facilities, and resists lateral loads from the new wellheads. Such hybrid conductor-supported tripod takes advantage of the axial compression capacities of the new conductors while its lateral resistance is provided by integrating only the new topside with the existing tripod's topside. Thus, the underwater structural modifications of the existing tripods are minimized. Design and construction challenges commonly encountered during the design phases of brownfield projects include: 1) lack of tripod jacket and foundation as-built data, 2) need for bracing the new conductors to the existing jacket underwater due to buckling and vortex issues, 3) as-built conditions of the tripods are already near their structural capacities. The design and construction issues experienced in low budget and tight schedule brownfield projects are alleviated with the use of a hybrid conductor-supported tripod. A parametric study was conducted to identify the minimum conductor pipe diameters needed for hybrid conductor-supported tripods at various shallow water depths in benign environmental conditions. The in-place conditions of several existing tripods were investigated before and after the hybrid conductor-supported tripods were integrated with the existing tripods. Using hybrid conductor-supported tripods enable production increase on existing facilities with minimal CAPEX investment. This is accomplished by: 1) utilizing existing tripods to increase production, 2) mitigating the need for as-built data, especially underwater jacket data, 3) eliminating additional axial loads on the existing tripods, 4) implementing minimum deck extensions on the existing tripods. The hybrid conductor-supported tripods provide the structural expansion need for the new wellhead facilities while keeping the existing tripods in their as-built conditions. Reducing the need for the current condition and the exact as-built underwater information of the existing tripods will accelerate the execution of the low budget and tight schedule production increase brownfield projects.
{"title":"Hybrid Conductor-Supported Tripod Platform: Brownfield Design Perspective to Unlock Production Capacity","authors":"S. Ozkul, Wen-Xing Huang, S. Taxy","doi":"10.4043/31157-ms","DOIUrl":"https://doi.org/10.4043/31157-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Oil and gas companies have shifted their investment priorities to low CAPEX brownfield projects in response to historically low oil and gas prices. One approach is to increase the production by drilling new wells and tying them back to existing tripods. However, existing tripods have limited as-built design data and are usually near the allowable structural capacity limits. This study introduces a novel concept of the \"hybrid conductor-supported tripod\" to support the new wellheads. This approach minimizes the need to modify the existing tripods.\u0000 \u0000 \u0000 \u0000 The hybrid conductor-supported tripod utilizes the new well conductors to support the wellheads, extends to the existing tripod topside to support the production facilities, and resists lateral loads from the new wellheads. Such hybrid conductor-supported tripod takes advantage of the axial compression capacities of the new conductors while its lateral resistance is provided by integrating only the new topside with the existing tripod's topside. Thus, the underwater structural modifications of the existing tripods are minimized.\u0000 \u0000 \u0000 \u0000 Design and construction challenges commonly encountered during the design phases of brownfield projects include: 1) lack of tripod jacket and foundation as-built data, 2) need for bracing the new conductors to the existing jacket underwater due to buckling and vortex issues, 3) as-built conditions of the tripods are already near their structural capacities. The design and construction issues experienced in low budget and tight schedule brownfield projects are alleviated with the use of a hybrid conductor-supported tripod. A parametric study was conducted to identify the minimum conductor pipe diameters needed for hybrid conductor-supported tripods at various shallow water depths in benign environmental conditions. The in-place conditions of several existing tripods were investigated before and after the hybrid conductor-supported tripods were integrated with the existing tripods. Using hybrid conductor-supported tripods enable production increase on existing facilities with minimal CAPEX investment. This is accomplished by: 1) utilizing existing tripods to increase production, 2) mitigating the need for as-built data, especially underwater jacket data, 3) eliminating additional axial loads on the existing tripods, 4) implementing minimum deck extensions on the existing tripods.\u0000 \u0000 \u0000 \u0000 The hybrid conductor-supported tripods provide the structural expansion need for the new wellhead facilities while keeping the existing tripods in their as-built conditions. Reducing the need for the current condition and the exact as-built underwater information of the existing tripods will accelerate the execution of the low budget and tight schedule production increase brownfield projects.\u0000","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89845102","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}
Paulino Bruno Santos, Teixeira Junior, Leonardo de Souza Nogueira, V. João, Simas G Milton Torres, Leonardo De Menezes Costa
In the last three years, COMPANY has started the production of eight Surface Production Systems (Floating, Production, Storage and Offloading Units) in the Búzios and Lula fields of the Brazilian pre-salt that have generated technical knowledge, organizational learning and many opportunities to explore in upcoming projects. The lessons learned as well as the organizational knowledge acquired in this period, resulted in a new approach for the commissioning process to apply in COMPANY's coming FPSO projects. During this period, COMPANY identified improvement opportunities and stablished structuring programs focused on adding value to these new assets. The main opportunity identified was to reduce the period required for ramping-up the oil production, considering aggressive target dates for start-up, with high up time on the gas compression systems with minimum flaring. In this manuscript, will be described some of the important actions and changes made in commissioning process that allowed COMPANY to achieve better efficiency and safety in ramp up of new FPSOs in Brazilian pre salt fields.
{"title":"From Basic Engineering to Ramp-Up: The New Successful Execution Approach for Commissioning in Brazil","authors":"Paulino Bruno Santos, Teixeira Junior, Leonardo de Souza Nogueira, V. João, Simas G Milton Torres, Leonardo De Menezes Costa","doi":"10.4043/31089-ms","DOIUrl":"https://doi.org/10.4043/31089-ms","url":null,"abstract":"\u0000 In the last three years, COMPANY has started the production of eight Surface Production Systems (Floating, Production, Storage and Offloading Units) in the Búzios and Lula fields of the Brazilian pre-salt that have generated technical knowledge, organizational learning and many opportunities to explore in upcoming projects. The lessons learned as well as the organizational knowledge acquired in this period, resulted in a new approach for the commissioning process to apply in COMPANY's coming FPSO projects.\u0000 During this period, COMPANY identified improvement opportunities and stablished structuring programs focused on adding value to these new assets. The main opportunity identified was to reduce the period required for ramping-up the oil production, considering aggressive target dates for start-up, with high up time on the gas compression systems with minimum flaring.\u0000 In this manuscript, will be described some of the important actions and changes made in commissioning process that allowed COMPANY to achieve better efficiency and safety in ramp up of new FPSOs in Brazilian pre salt fields.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"70 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83808113","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}
E. Schnitzler, L. F. Gonçalez, Roger Savoldi Roman, M. Marques, Fábio Rosas Gutterres, Manoel Feliciano Silva, Carlos Alexandre Belo Castilho
This paper describes the challenges faced on the deployment of intelligent well completion (IWC) systems in some of the wells built in Buzios field, mostly related to heavy fluid losses that occurred during the well construction. It also presents the solutions used to overcome them. This kind of event affects not only drilling and casing cementing operations, but may also prevent a safe and efficient installation of the completion system as initially designed. The IWC design typically used in Brazilian pre-salt areas comprises cased hole wells. Perforation operations must be performed before installing the integral completion system, as it does not include a separation between upper and lower completion. Therefore, the reservoir remains communicated to the wellbore during the whole completion installation process, frequently requiring prior fluid loss control as to allow safe deployment. Rock characteristics found in this field make it difficult to effectively control losses in some of the wells, requiring the use of different well construction practices that led to the development of some new well designs. The well engineering team developed a new well concept, where a separated lower completion system is installed in open hole, delivering temporary reservoir isolation. This new well architecture not only delivers reduced drilling and completion duration and costs, but also provides the IWC features in wells with major fluid losses. This is possible by the use of multiple managed pressure drilling (MPD) techniques when required, which were considered since the initial design phase. Safe and effective construction of some wells in pre-salt fields was considered not feasible before the adoption of MPD solutions, both for drilling and completions. Other important aspects considered on the new well design are the large thickness and high productivity of Buzios field reservoirs, as well as the need of some flexibility to deal with uncertainties. Finally, the new completion project was also designed to improve performance and safety on future challenging heavy workover interventions. The well construction area has gradually obtained improved performance in Buzios field with the adoption of the new practices and well design presented in this paper. The new solutions developed for Buzios field have set a new drilling and completion philosophy for pre-salt wells, setting the grounds for future projects. The improved performance is essential to keep these deepwater projects competitive, especially in challenging oil price scenarios. One of the groundbreaking solutions used is the possibility of installing the lower completion using managed pressure drilling techniques.
{"title":"Buzios Presalt Wells: Delivering Intelligent Completion In Ultra-Deepwater Carbonate Reservoirs","authors":"E. Schnitzler, L. F. Gonçalez, Roger Savoldi Roman, M. Marques, Fábio Rosas Gutterres, Manoel Feliciano Silva, Carlos Alexandre Belo Castilho","doi":"10.4043/31116-ms","DOIUrl":"https://doi.org/10.4043/31116-ms","url":null,"abstract":"\u0000 This paper describes the challenges faced on the deployment of intelligent well completion (IWC) systems in some of the wells built in Buzios field, mostly related to heavy fluid losses that occurred during the well construction. It also presents the solutions used to overcome them. This kind of event affects not only drilling and casing cementing operations, but may also prevent a safe and efficient installation of the completion system as initially designed.\u0000 The IWC design typically used in Brazilian pre-salt areas comprises cased hole wells. Perforation operations must be performed before installing the integral completion system, as it does not include a separation between upper and lower completion. Therefore, the reservoir remains communicated to the wellbore during the whole completion installation process, frequently requiring prior fluid loss control as to allow safe deployment. Rock characteristics found in this field make it difficult to effectively control losses in some of the wells, requiring the use of different well construction practices that led to the development of some new well designs.\u0000 The well engineering team developed a new well concept, where a separated lower completion system is installed in open hole, delivering temporary reservoir isolation. This new well architecture not only delivers reduced drilling and completion duration and costs, but also provides the IWC features in wells with major fluid losses. This is possible by the use of multiple managed pressure drilling (MPD) techniques when required, which were considered since the initial design phase. Safe and effective construction of some wells in pre-salt fields was considered not feasible before the adoption of MPD solutions, both for drilling and completions.\u0000 Other important aspects considered on the new well design are the large thickness and high productivity of Buzios field reservoirs, as well as the need of some flexibility to deal with uncertainties. Finally, the new completion project was also designed to improve performance and safety on future challenging heavy workover interventions. The well construction area has gradually obtained improved performance in Buzios field with the adoption of the new practices and well design presented in this paper.\u0000 The new solutions developed for Buzios field have set a new drilling and completion philosophy for pre-salt wells, setting the grounds for future projects. The improved performance is essential to keep these deepwater projects competitive, especially in challenging oil price scenarios. One of the groundbreaking solutions used is the possibility of installing the lower completion using managed pressure drilling techniques.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90906156","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}
S. Taghavi, E. Gisholt, H. Aakre, Stian Håland, K. Langaas
Early water and/or gas breakthrough is one of the main challenges in oil production which results in inefficient oil recovery. Existing mature wells must stop the production and shut down due to high gas oil ratio (GOR) and/or water cut (WC) although considerable amounts of oil still present along the reservoir. It is important to develop technologies that can increase oil production and recovery for marginal, mature, and challenging oil reservoirs. In most fields the drainage mechanism is pressure support from gas and/or water and the multiphase flow performance is particularly important. Autonomous Inflow Control Valve (AICV) can delay the onset of breakthrough by balancing the inflow along the horizontal section and control or shut off completely the unwanted fluid production when the breakthrough occurs. The AICV was tested in a world-leading full-scale multiphase flow loop located in Porsgrunn, Norway. Tests were performed with realistic reservoir conditions, i.e. reservoir pressure and temperature, crude oil, formation water and hydrocarbon gas at various gas oil ratio and water cut in addition to single phase performances. A summary of the flow loop, test conditions, the operating procedures, and test results are presented. In addition, how to represent the well with AICVs in a standard reservoir simulation model are discussed. The AICV flow performance curves for both single phase and multiphase flow are presented, discussed, and compared to conventional Inflow Control Device (ICD) performance. The test results demonstrate that the AICV flow performance is significantly better than conventional ICD. The AICV impact on a simplified model of a thin oil rim reservoir is shown and modelling limitations are discussed. The simulation results along with the experimental results demonstrated considerable benefit of deploying AICV in this thin oil rim reservoir. Furthermore, this paper describes a novel approach towards the application of testing the AICV for use within light oil completion designs and how the AICV flow performance results can be utilized in marginal, mature, and other challenging oil reservoirs.
{"title":"Autonomous Inflow Control Valve Multiphase Flow Performance for Light Oil","authors":"S. Taghavi, E. Gisholt, H. Aakre, Stian Håland, K. Langaas","doi":"10.4043/31239-ms","DOIUrl":"https://doi.org/10.4043/31239-ms","url":null,"abstract":"\u0000 Early water and/or gas breakthrough is one of the main challenges in oil production which results in inefficient oil recovery. Existing mature wells must stop the production and shut down due to high gas oil ratio (GOR) and/or water cut (WC) although considerable amounts of oil still present along the reservoir. It is important to develop technologies that can increase oil production and recovery for marginal, mature, and challenging oil reservoirs. In most fields the drainage mechanism is pressure support from gas and/or water and the multiphase flow performance is particularly important. Autonomous Inflow Control Valve (AICV) can delay the onset of breakthrough by balancing the inflow along the horizontal section and control or shut off completely the unwanted fluid production when the breakthrough occurs. The AICV was tested in a world-leading full-scale multiphase flow loop located in Porsgrunn, Norway. Tests were performed with realistic reservoir conditions, i.e. reservoir pressure and temperature, crude oil, formation water and hydrocarbon gas at various gas oil ratio and water cut in addition to single phase performances. A summary of the flow loop, test conditions, the operating procedures, and test results are presented. In addition, how to represent the well with AICVs in a standard reservoir simulation model are discussed. The AICV flow performance curves for both single phase and multiphase flow are presented, discussed, and compared to conventional Inflow Control Device (ICD) performance. The test results demonstrate that the AICV flow performance is significantly better than conventional ICD. The AICV impact on a simplified model of a thin oil rim reservoir is shown and modelling limitations are discussed.\u0000 The simulation results along with the experimental results demonstrated considerable benefit of deploying AICV in this thin oil rim reservoir. Furthermore, this paper describes a novel approach towards the application of testing the AICV for use within light oil completion designs and how the AICV flow performance results can be utilized in marginal, mature, and other challenging oil reservoirs.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78984596","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. LeCompte, Tosin Majekodunmi, M. Staines, Gareth Taylor, Barry Zhang, R. Evans, N. Chang
The objective of the paper is to describe the application of artificial intelligence software to predict formation evaluation logs (compressional sonic, shear sonic and density) using only gamma ray, and resistivity log data and drilling dynamics data as received by the electronic drilling recorder (EDR). The software was applied real-time as a well was being drilled in deepwater Gulf of Mexico. Thorough examination and conditioning of EDR and wireline data give way to a training model construction for the artificial neural network (ANN) using full suites of log-data in offset wells. Next, a neural network architecture and associated hyperparameters are chosen and tested. The fully trained and validated model is applied to the gamma ray, resistivity and EDR of the target well while drilling. Real-time EDR and wireline data flow via WITSML from rig to cloud and data is delivered to the client. The results of the study indicate the simulated log data were comparable to those measured from conventional logging tools over the study area. In both blind well tests the density agreed with the conventional log results within 1.1 % and the compressional within 2.51 % (Figure 1). Each of these is well within the range of variance expected of repeat runs of a conventional logging tool. A primary driver for near real-time logs was to confirm structural depth of the target sands along the well bore. There was a depleted sand below the expected TD of the well that, if encountered, could have led to total losses and possible loss of the wellbore. It was critical to have real-time logs to characterize the sands above the depleted sand, using every possible petrophysical and geologic character to refine the log correlation. This integration of all the logs provided the best interpretation of the sand quality and led toward the completion decision. AI-based logs are a highly cost-effective alternative to LWD logging. It presents an environmentally friendly approach as there is no logging personnel on-site and no expensive and potentially dangerous nuclear sources in the hole The deployment of this patented, machine learning-driven, real-time simulation of formation evaluation logs is unique in using only gamma ray, resistivity and drilling data. It is particularly useful in the overburden section where formation evaluation tools are often not run for cost reasons, in side-tracks, in HP/HT settings and operational risk mitigation. It provides additive data for other petrophysical/QI/rock property analyses including seismic inversion, shale content, porosity, log QC/editing, real-time LWD, drilling optimization, etc.
{"title":"Machine Learning Prediction of Formation Evaluation Logs in the Gulf of Mexico","authors":"B. LeCompte, Tosin Majekodunmi, M. Staines, Gareth Taylor, Barry Zhang, R. Evans, N. Chang","doi":"10.4043/31093-ms","DOIUrl":"https://doi.org/10.4043/31093-ms","url":null,"abstract":"\u0000 The objective of the paper is to describe the application of artificial intelligence software to predict formation evaluation logs (compressional sonic, shear sonic and density) using only gamma ray, and resistivity log data and drilling dynamics data as received by the electronic drilling recorder (EDR). The software was applied real-time as a well was being drilled in deepwater Gulf of Mexico.\u0000 Thorough examination and conditioning of EDR and wireline data give way to a training model construction for the artificial neural network (ANN) using full suites of log-data in offset wells. Next, a neural network architecture and associated hyperparameters are chosen and tested. The fully trained and validated model is applied to the gamma ray, resistivity and EDR of the target well while drilling. Real-time EDR and wireline data flow via WITSML from rig to cloud and data is delivered to the client. The results of the study indicate the simulated log data were comparable to those measured from conventional logging tools over the study area. In both blind well tests the density agreed with the conventional log results within 1.1 % and the compressional within 2.51 % (Figure 1). Each of these is well within the range of variance expected of repeat runs of a conventional logging tool. A primary driver for near real-time logs was to confirm structural depth of the target sands along the well bore. There was a depleted sand below the expected TD of the well that, if encountered, could have led to total losses and possible loss of the wellbore. It was critical to have real-time logs to characterize the sands above the depleted sand, using every possible petrophysical and geologic character to refine the log correlation. This integration of all the logs provided the best interpretation of the sand quality and led toward the completion decision. AI-based logs are a highly cost-effective alternative to LWD logging. It presents an environmentally friendly approach as there is no logging personnel on-site and no expensive and potentially dangerous nuclear sources in the hole\u0000 The deployment of this patented, machine learning-driven, real-time simulation of formation evaluation logs is unique in using only gamma ray, resistivity and drilling data. It is particularly useful in the overburden section where formation evaluation tools are often not run for cost reasons, in side-tracks, in HP/HT settings and operational risk mitigation. It provides additive data for other petrophysical/QI/rock property analyses including seismic inversion, shale content, porosity, log QC/editing, real-time LWD, drilling optimization, etc.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80226756","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}
Z. Westgate, R. Argiolas, R. Wallerand, J. Ballard
This paper is a companion paper to OTC 28671, titled "Experience with Interface Shear Box Testing for Axial Pipe-Soil Interaction Assessment on Soft Clay", and presents a similar range of experience and best practice recommendations for geotechnical laboratory testing to determine soil properties relevant to pipeline-seabed friction on sandy seabeds. The paper is underpinned by a new database that demonstrates the driving parameters that influence interface friction in granular materials. By accurately quantifying shear resistance along the pipe-soil interface under low normal stresses imposed by subsea pipelines, design ranges in friction can be narrowed and/or tailored to specific pipeline conditions. These improved geotechnical inputs to pipe-soil interaction can alleviate unnecessary axial expansion mitigation and lateral stabilization measures, unlocking cost savings otherwise unavailable through conventional testing. A large database is presented, compiled from both previously published research and unpublished recent industry experience with low normal stress interface shear testing using various modified direct shear box devices. The test database comprises several coarse-grained soil types of both silica and carbonate minerology tested against pipeline coatings of various material, hardness and roughness. The database populates a framework for assessing frictional pipe-soil interaction response, illuminating key trends from normal stress, interface roughness and hardness, and particle angularity, which otherwise remain elusive when examined through individual test datasets. This database and the populated framework provides guidance to pipeline and geotechnical engineers in the form of a basis for initial estimates of axial and lateral friction of pipelines on sand and an approach for improving these estimates via focused site-specific testing. The test database includes previously unreleased project data collected over the past few years for offshore oil and gas projects. Similar to its predecessor paper on soft clays (OTC 28671), this paper shares the authors’ collective experience providing guidance on the planning, execution and interpretation of low stress interface shear tests in sands. The combined databases across both papers provide a significant improvement in early stage guidance for characterization of geotechnical soil properties for subsea pipeline design.
{"title":"Experience with Interface Shear Box Testing for Pipe-Soil Interaction Assessment on Sand","authors":"Z. Westgate, R. Argiolas, R. Wallerand, J. Ballard","doi":"10.4043/31268-ms","DOIUrl":"https://doi.org/10.4043/31268-ms","url":null,"abstract":"\u0000 This paper is a companion paper to OTC 28671, titled \"Experience with Interface Shear Box Testing for Axial Pipe-Soil Interaction Assessment on Soft Clay\", and presents a similar range of experience and best practice recommendations for geotechnical laboratory testing to determine soil properties relevant to pipeline-seabed friction on sandy seabeds. The paper is underpinned by a new database that demonstrates the driving parameters that influence interface friction in granular materials. By accurately quantifying shear resistance along the pipe-soil interface under low normal stresses imposed by subsea pipelines, design ranges in friction can be narrowed and/or tailored to specific pipeline conditions. These improved geotechnical inputs to pipe-soil interaction can alleviate unnecessary axial expansion mitigation and lateral stabilization measures, unlocking cost savings otherwise unavailable through conventional testing.\u0000 A large database is presented, compiled from both previously published research and unpublished recent industry experience with low normal stress interface shear testing using various modified direct shear box devices. The test database comprises several coarse-grained soil types of both silica and carbonate minerology tested against pipeline coatings of various material, hardness and roughness.\u0000 The database populates a framework for assessing frictional pipe-soil interaction response, illuminating key trends from normal stress, interface roughness and hardness, and particle angularity, which otherwise remain elusive when examined through individual test datasets. This database and the populated framework provides guidance to pipeline and geotechnical engineers in the form of a basis for initial estimates of axial and lateral friction of pipelines on sand and an approach for improving these estimates via focused site-specific testing.\u0000 The test database includes previously unreleased project data collected over the past few years for offshore oil and gas projects. Similar to its predecessor paper on soft clays (OTC 28671), this paper shares the authors’ collective experience providing guidance on the planning, execution and interpretation of low stress interface shear tests in sands. The combined databases across both papers provide a significant improvement in early stage guidance for characterization of geotechnical soil properties for subsea pipeline design.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79531537","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. H. Yusof, M. Z. Sulaiman, Rahimah A. Halim, Nurfaridah Bt Ahmad Fauzi, Ahgheelan Sella Thurai, Masseera Mahictin, Tg Zuhaili Tg Yahya, Fadli Adlan Muslim
This paper discusses the Case study of Field A in offshore Sarawak, Malaysia which focus on re-thinking development based on statistical analysis of the fields. Conventionally, well design is driven by subsurface requirement by targeting the high-reserve sand and well is designed to meet subsurface objectives. However, the conventional way may not be efficient to develop matured field environment due to the high CAPEX and the inconsistencies among well design especially in current volatile oil price period. The objective of this fit-for-purpose approach which is called "Cone Concept Statistical Approach" is to steer away from the conventional way of targeting only sweet spots whilst leaving the remaining potential resources undeveloped. Based on the statistical analysis and subsurface fields pattern, the "Cone Concept Statistical Approach" in which standardizing well design and trajectories was developed to extract the whole fields’ reserve at maximum. Well design boundaries were introduced to ensure this approach can be replicated throughout the field. Not only this study covers drilling perspective, completion perspective was also taken into consideration by exploring a cheaper and fit for purpose sand control method, considering it is a matured field with relatively short remaining field life. The Well Cost Catalogue for this field-specific was also developed which contains different types of design and completion, in order to holistically evaluate sand control method and identify the best option for the project moving forward. This "Cone Concept Statistical Approach" aims to enable operator to drill more simple wells within the same allocated budget in which poses low-to-none risk in the design and execution phase, promoting learning curve to improve operation & HSE, and ultimately to get positive project economics. Since this simple approach can be implemented early on even during the pre-FEL stage, the FDP team & host authority can come together to jointly discuss the targets/platform ranking and segregate them into various phases. Hence, the number of platforms or drilling centers, and its location also can be optimized early on with this concept, and again, translating into further reduction in overall project cost. This paper will help other operators and host authority to understand better on how a specific development concept on statistical approach can result and turn the matured-challenging fields into more economically attractive projects – low overall development cost and maximizing the recovery.
{"title":"Delivering Low Cost Wells at Matured Field with Enhanced Statistical Approach","authors":"M. H. Yusof, M. Z. Sulaiman, Rahimah A. Halim, Nurfaridah Bt Ahmad Fauzi, Ahgheelan Sella Thurai, Masseera Mahictin, Tg Zuhaili Tg Yahya, Fadli Adlan Muslim","doi":"10.4043/30994-ms","DOIUrl":"https://doi.org/10.4043/30994-ms","url":null,"abstract":"\u0000 This paper discusses the Case study of Field A in offshore Sarawak, Malaysia which focus on re-thinking development based on statistical analysis of the fields. Conventionally, well design is driven by subsurface requirement by targeting the high-reserve sand and well is designed to meet subsurface objectives. However, the conventional way may not be efficient to develop matured field environment due to the high CAPEX and the inconsistencies among well design especially in current volatile oil price period. The objective of this fit-for-purpose approach which is called \"Cone Concept Statistical Approach\" is to steer away from the conventional way of targeting only sweet spots whilst leaving the remaining potential resources undeveloped. Based on the statistical analysis and subsurface fields pattern, the \"Cone Concept Statistical Approach\" in which standardizing well design and trajectories was developed to extract the whole fields’ reserve at maximum. Well design boundaries were introduced to ensure this approach can be replicated throughout the field. Not only this study covers drilling perspective, completion perspective was also taken into consideration by exploring a cheaper and fit for purpose sand control method, considering it is a matured field with relatively short remaining field life. The Well Cost Catalogue for this field-specific was also developed which contains different types of design and completion, in order to holistically evaluate sand control method and identify the best option for the project moving forward.\u0000 This \"Cone Concept Statistical Approach\" aims to enable operator to drill more simple wells within the same allocated budget in which poses low-to-none risk in the design and execution phase, promoting learning curve to improve operation & HSE, and ultimately to get positive project economics. Since this simple approach can be implemented early on even during the pre-FEL stage, the FDP team & host authority can come together to jointly discuss the targets/platform ranking and segregate them into various phases. Hence, the number of platforms or drilling centers, and its location also can be optimized early on with this concept, and again, translating into further reduction in overall project cost. This paper will help other operators and host authority to understand better on how a specific development concept on statistical approach can result and turn the matured-challenging fields into more economically attractive projects – low overall development cost and maximizing the recovery.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79434216","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}
Estimating rock facies from petrophysical logs in non-cored wells in complex carbonates represents a crucial task for improving reservoir characterization and field development. Thus, it most essential to identify the lithofacies that discriminate the reservoir intervals based on their flow and storage capacity. In this paper, an innovative procedure is adopted for lithofacies classification using data-driven machine learning in a well from the Mishrif carbonate reservoir in the giant Majnoon oil field, Southern Iraq. The Random Forest method was adopted for lithofacies classification using well logging data in a cored well to predict their distribution in other non-cored wells. Furthermore, three advanced statistical algorithms: Logistic Boosting Regression, Bagging Multivariate Adaptive Regression Spline, and Generalized Boosting Modeling were implemented and compared to the Random Forest approach to attain the most realistic lithofacies prediction. The dataset includes the measured discrete lithofacies distribution and the original log curves of caliper, gamma ray, neutron porosity, bulk density, sonic, deep and shallow resistivity, all available over the entire reservoir interval. Prior to applying the four classification algorithms, a random subsampling cross-validation was conducted on the dataset to produce training and testing subsets for modeling and prediction, respectively. After predicting the discrete lithofacies distribution, the Confusion Table and the Correct Classification Rate Index (CCI) were employed as further criteria to analyze and compare the effectiveness of the four classification algorithms. The results of this study revealed that Random Forest was more accurate in lithofacies classification than other techniques. It led to excellent matching between the observed and predicted discrete lithofacies through attaining 100% of CCI based on the training subset and 96.67 % of the CCI for the validating subset. Further validation of the resulting facies model was conducted by comparing each of the predicted discrete lithofacies with the available ranges of porosity and permeability obtained from the NMR log. We observed that rudist-dominated lithofacies correlates to rock with higher porosity and permeability. In contrast, the argillaceous lithofacies correlates to rocks with lower porosity and permeability. Additionally, these high-and low-ranges of permeability were later compared with the oil rate obtained from the PLT log data. It was identified that the high-and low-ranges of permeability correlate well to the high- and low-oil rate logs, respectively. In conclusion, the high quality estimation of lithofacies in non-cored intervals and wells is a crucial reservoir characterization task in order to obtain meaningful permeability-porosity relationships and capture realistic reservoir heterogeneity. The application of machine learning techniques drives down costs, provides for time-savings, and allows for uncertainty mi
{"title":"Lithofacies Classification of Carbonate Reservoirs Using Advanced Machine Learning: A Case Study from a Southern Iraqi Oil Field","authors":"Mohammed A. Abbas, W. Al-Mudhafar","doi":"10.4043/31114-ms","DOIUrl":"https://doi.org/10.4043/31114-ms","url":null,"abstract":"\u0000 Estimating rock facies from petrophysical logs in non-cored wells in complex carbonates represents a crucial task for improving reservoir characterization and field development. Thus, it most essential to identify the lithofacies that discriminate the reservoir intervals based on their flow and storage capacity. In this paper, an innovative procedure is adopted for lithofacies classification using data-driven machine learning in a well from the Mishrif carbonate reservoir in the giant Majnoon oil field, Southern Iraq.\u0000 The Random Forest method was adopted for lithofacies classification using well logging data in a cored well to predict their distribution in other non-cored wells. Furthermore, three advanced statistical algorithms: Logistic Boosting Regression, Bagging Multivariate Adaptive Regression Spline, and Generalized Boosting Modeling were implemented and compared to the Random Forest approach to attain the most realistic lithofacies prediction. The dataset includes the measured discrete lithofacies distribution and the original log curves of caliper, gamma ray, neutron porosity, bulk density, sonic, deep and shallow resistivity, all available over the entire reservoir interval.\u0000 Prior to applying the four classification algorithms, a random subsampling cross-validation was conducted on the dataset to produce training and testing subsets for modeling and prediction, respectively. After predicting the discrete lithofacies distribution, the Confusion Table and the Correct Classification Rate Index (CCI) were employed as further criteria to analyze and compare the effectiveness of the four classification algorithms. The results of this study revealed that Random Forest was more accurate in lithofacies classification than other techniques. It led to excellent matching between the observed and predicted discrete lithofacies through attaining 100% of CCI based on the training subset and 96.67 % of the CCI for the validating subset. Further validation of the resulting facies model was conducted by comparing each of the predicted discrete lithofacies with the available ranges of porosity and permeability obtained from the NMR log. We observed that rudist-dominated lithofacies correlates to rock with higher porosity and permeability. In contrast, the argillaceous lithofacies correlates to rocks with lower porosity and permeability. Additionally, these high-and low-ranges of permeability were later compared with the oil rate obtained from the PLT log data. It was identified that the high-and low-ranges of permeability correlate well to the high- and low-oil rate logs, respectively.\u0000 In conclusion, the high quality estimation of lithofacies in non-cored intervals and wells is a crucial reservoir characterization task in order to obtain meaningful permeability-porosity relationships and capture realistic reservoir heterogeneity. The application of machine learning techniques drives down costs, provides for time-savings, and allows for uncertainty mi","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78849148","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}
Dingwei Zhu, Svein Normann, Minli Xie, John R. Haugen
Thermosetting resin is gaining more acceptances in Plug and Abandonment due to its excellent mechanical properties after set and ability for placement in locations cement cannot reach. A thorough understanding of its curing behavior such as gel time is essential to ensure safe placement and a good seal. This paper investigates the pressure-sensitive gelation behavior of polymer resin under in-situ conditions, and the pressure effect on the gel time of thermosetting resin was evaluated. An innovative assessment methodology named CAPT (Consistency under Applied Pressure Test) was created to assess the curing process of thermoset resins in a pressurized consistometer. A series of resin samples were tested at temperatures ranging from ambient to 120°C with applied pressures up to 10,000 psi. The consistency was initially used to indicate the gel structure development of the resin while it was gelling. Based on the consistency data, the relationship between applied pressure and gel time of resins was studied and a new approach of modeling the curing process with the influence factor of pressure was proposed. The primary observation was the confirmation that the gelation process of thermosetting resin under applied pressure was faster than that under atmospheric pressure. However, the gel time had big variations. The pressure sensitivity mainly depended on the initiators and it was only partly dependent on the temperature. There was a threshold value for the pressure effect on the gel time. Below the threshold, the gel time only decreased by around 5%. Above the threshold, the pressure effect was much larger where the gel time decreased by 20% - 30%. This could be mainly attributed to the thermodynamic effect caused by pressure accelerating the polymerization process, resulting in a shorter gel time. Meanwhile, these results help explain why the curing behavior of thermosetting resin placed underground where high pressure is encountered often differs from the laboratory-predicted performance. Besides indicating the relative strength development, consistency analysis could also be used to assess the pressure effect on the gelation process of a resin sample in down-hole operations with applied pressures. Thus, CAPT would be more suitable than a conventional reactivity test to propose a new approach of modeling the gel time of thermosetting resin systems with the influence factor of pressure. CAPT is a novel method to accurately evaluate the curing process of thermosetting resin and indicate its relative strength development. This helps engineers reach a good balance between designing proper operations and preserving mechanical properties in the plug and abandonment process.
{"title":"Consistency Under Applied Pressure Test CAPT - A Novel Method for Evaluating Pressure Effect on the Gel Time of Thermosetting Resin","authors":"Dingwei Zhu, Svein Normann, Minli Xie, John R. Haugen","doi":"10.4043/31236-ms","DOIUrl":"https://doi.org/10.4043/31236-ms","url":null,"abstract":"\u0000 Thermosetting resin is gaining more acceptances in Plug and Abandonment due to its excellent mechanical properties after set and ability for placement in locations cement cannot reach. A thorough understanding of its curing behavior such as gel time is essential to ensure safe placement and a good seal. This paper investigates the pressure-sensitive gelation behavior of polymer resin under in-situ conditions, and the pressure effect on the gel time of thermosetting resin was evaluated.\u0000 An innovative assessment methodology named CAPT (Consistency under Applied Pressure Test) was created to assess the curing process of thermoset resins in a pressurized consistometer. A series of resin samples were tested at temperatures ranging from ambient to 120°C with applied pressures up to 10,000 psi. The consistency was initially used to indicate the gel structure development of the resin while it was gelling. Based on the consistency data, the relationship between applied pressure and gel time of resins was studied and a new approach of modeling the curing process with the influence factor of pressure was proposed.\u0000 The primary observation was the confirmation that the gelation process of thermosetting resin under applied pressure was faster than that under atmospheric pressure. However, the gel time had big variations. The pressure sensitivity mainly depended on the initiators and it was only partly dependent on the temperature. There was a threshold value for the pressure effect on the gel time. Below the threshold, the gel time only decreased by around 5%. Above the threshold, the pressure effect was much larger where the gel time decreased by 20% - 30%. This could be mainly attributed to the thermodynamic effect caused by pressure accelerating the polymerization process, resulting in a shorter gel time. Meanwhile, these results help explain why the curing behavior of thermosetting resin placed underground where high pressure is encountered often differs from the laboratory-predicted performance. Besides indicating the relative strength development, consistency analysis could also be used to assess the pressure effect on the gelation process of a resin sample in down-hole operations with applied pressures. Thus, CAPT would be more suitable than a conventional reactivity test to propose a new approach of modeling the gel time of thermosetting resin systems with the influence factor of pressure.\u0000 CAPT is a novel method to accurately evaluate the curing process of thermosetting resin and indicate its relative strength development. This helps engineers reach a good balance between designing proper operations and preserving mechanical properties in the plug and abandonment process.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75133111","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}
Well testing could be described as a process required to calculate the volumes of (oil, water and gas) production from a well in a bid to identify the current state of the well. Amongst other things, well testing aims to provide information for effective Well, Reservoir and Facility Management. Normally, as a means of well performance health-check, reconciliation factor (RF) is generated by comparing the fiscal production volume against the theoretical well test volume. Experiences from the Coronavirus pandemic has brought about the new normal into well test execution. In deepwater environment, the process of well testing is more challenging and this paper aims to address these challenges and propose optimum well test frequency for deepwater operations. It is usually required that routine well test be conducted once every month on all flowing strings, this is for statutory compliance and well health-check purposes. However, in deepwater environment, it is difficult to comply with this periodic well test requirement mainly due to production flow line slugging, plant process upset and/or tripping resulting in production deferment and operational risk exposure. Furthermore, to carry out well test in deepwater operation, production cutback is required for flow assurance purpose and this usually results in huge production deferment. In this field of interest, this challenge has been managed by deploying a data-driven application to monitor production on individual flowing strings in real-time thereby optimizing the frequency of well test on every flowing well. Varying rate well test data are captured and used to calibrate this tool or application for subsequent real-time production monitoring. This initiative ensures that all the challenges earlier mentioned are managed while actually optimizing the frequency of testing the wells using intelligent application which serves as a ‘virtual meter’ for testing all producing wells in real time. As mentioned, well testing in most deepwater assets remain a big challenge but this project based field experience has ensured effective well testing operation resulting in reduction of production deferment and safety exposure during plant tripping whilst optimizing frequency of testing the wells. Following this achievement of the optimized well test to quarterly frequency in this field in Nigerian deepwater, recommendation from this paper will assist other deepwater field operators in managing routine well testing operation optimally.
{"title":"Empirical Design of Optimum Frequency of Well Testing for Deepwater Operation","authors":"E. Udofia","doi":"10.4043/31180-ms","DOIUrl":"https://doi.org/10.4043/31180-ms","url":null,"abstract":"\u0000 Well testing could be described as a process required to calculate the volumes of (oil, water and gas) production from a well in a bid to identify the current state of the well. Amongst other things, well testing aims to provide information for effective Well, Reservoir and Facility Management. Normally, as a means of well performance health-check, reconciliation factor (RF) is generated by comparing the fiscal production volume against the theoretical well test volume. Experiences from the Coronavirus pandemic has brought about the new normal into well test execution. In deepwater environment, the process of well testing is more challenging and this paper aims to address these challenges and propose optimum well test frequency for deepwater operations.\u0000 It is usually required that routine well test be conducted once every month on all flowing strings, this is for statutory compliance and well health-check purposes. However, in deepwater environment, it is difficult to comply with this periodic well test requirement mainly due to production flow line slugging, plant process upset and/or tripping resulting in production deferment and operational risk exposure. Furthermore, to carry out well test in deepwater operation, production cutback is required for flow assurance purpose and this usually results in huge production deferment. In this field of interest, this challenge has been managed by deploying a data-driven application to monitor production on individual flowing strings in real-time thereby optimizing the frequency of well test on every flowing well. Varying rate well test data are captured and used to calibrate this tool or application for subsequent real-time production monitoring. This initiative ensures that all the challenges earlier mentioned are managed while actually optimizing the frequency of testing the wells using intelligent application which serves as a ‘virtual meter’ for testing all producing wells in real time.\u0000 As mentioned, well testing in most deepwater assets remain a big challenge but this project based field experience has ensured effective well testing operation resulting in reduction of production deferment and safety exposure during plant tripping whilst optimizing frequency of testing the wells. Following this achievement of the optimized well test to quarterly frequency in this field in Nigerian deepwater, recommendation from this paper will assist other deepwater field operators in managing routine well testing operation optimally.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"71 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72616223","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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