Leak-off pressure (LOP) is an important parameter to determine a weight of drilling mud and in-situ horizontal stresses. When the well pressure become higher than the LOP, it can cause a wellbore instability during drilling, such as a mud loss. Thus, accurate prediction of LOP is important for safe and economical drilling for the oil and gas industry. In this study, we present a novel prediction model for the leak-off pressure (LOP) offshore Norway. The model uses a deep neural network (DNN) applied on a public wellbore database provided by the Norwegian Petroleum Directorate (NPD). We used a Python-based web scrapping tool to collect data from more than 6400 wells (1800 exploration wells and 4600 development wells) from the NPD factpages. Then, we analyzed the collected data to investigate impacts of spatial and regional factors on the collected LOPs. The DNN model was structured to predict the leak off pressure offshore Norway using open source libraries Keras and Tensor Flow. The model tests have various hidden layers (i.e. 3, 5, and 10 layers). In order to avoid overfitting, we specified an early-stop algorithm. In our study, we took 80% of the data as the training set keeping the remaining 20% to test the model. In total, the database consists of around 3000 leak-off pressure data from about 1800 exploration wells, and grouped in geographical area (North Sea, Norwegian Sea, Barents Sea groups). The LOPs of the North Sea and the Norwegian Sea show a bi-linear trend with depth. The LOPs that are measured from deeper than 2-3 km below sea level show clear a deviation in trend, with a steeper increase compared to the shallower section. The steeper part of the bi-linear trend at greated sub-surface depths can be related to a coupling with tectonic stresses from base rocks. The data from the Barents Sea shows more scattered LOP compared to the other regions offshore Norway. The scattered data seem to relate to the complex geological history on the Barents sea. In general, the accuracy of the prediction increases with the number of hidden layers. However, when the number of the hidden layer exceed 5, there was no significant improvement in the accuracy of prediction. The validation test shows relatively good prediction of LOP with an MAE (Mean Absolute Error) of less than 0.07 even for areas experiencing complex geological history such as the deep subsurface of the Norwegian Sea and the shallow subsurface of the Barents sea. This study clearly demonstrates how a data-driven approach combined with machine learning algorithms can provide hidden patterns of not only LOP itself but also the additional information about the lithology, the stress history and the geographical frequency of exploration.
{"title":"Deep Neural Network Based Prediction of Leak-Off Pressure in Offshore Norway","authors":"J. Choi, E. Skurtveit, L. Grande","doi":"10.4043/29454-MS","DOIUrl":"https://doi.org/10.4043/29454-MS","url":null,"abstract":"\u0000 Leak-off pressure (LOP) is an important parameter to determine a weight of drilling mud and in-situ horizontal stresses. When the well pressure become higher than the LOP, it can cause a wellbore instability during drilling, such as a mud loss. Thus, accurate prediction of LOP is important for safe and economical drilling for the oil and gas industry. In this study, we present a novel prediction model for the leak-off pressure (LOP) offshore Norway. The model uses a deep neural network (DNN) applied on a public wellbore database provided by the Norwegian Petroleum Directorate (NPD).\u0000 We used a Python-based web scrapping tool to collect data from more than 6400 wells (1800 exploration wells and 4600 development wells) from the NPD factpages. Then, we analyzed the collected data to investigate impacts of spatial and regional factors on the collected LOPs. The DNN model was structured to predict the leak off pressure offshore Norway using open source libraries Keras and Tensor Flow. The model tests have various hidden layers (i.e. 3, 5, and 10 layers). In order to avoid overfitting, we specified an early-stop algorithm. In our study, we took 80% of the data as the training set keeping the remaining 20% to test the model. In total, the database consists of around 3000 leak-off pressure data from about 1800 exploration wells, and grouped in geographical area (North Sea, Norwegian Sea, Barents Sea groups).\u0000 The LOPs of the North Sea and the Norwegian Sea show a bi-linear trend with depth. The LOPs that are measured from deeper than 2-3 km below sea level show clear a deviation in trend, with a steeper increase compared to the shallower section. The steeper part of the bi-linear trend at greated sub-surface depths can be related to a coupling with tectonic stresses from base rocks. The data from the Barents Sea shows more scattered LOP compared to the other regions offshore Norway. The scattered data seem to relate to the complex geological history on the Barents sea. In general, the accuracy of the prediction increases with the number of hidden layers. However, when the number of the hidden layer exceed 5, there was no significant improvement in the accuracy of prediction. The validation test shows relatively good prediction of LOP with an MAE (Mean Absolute Error) of less than 0.07 even for areas experiencing complex geological history such as the deep subsurface of the Norwegian Sea and the shallow subsurface of the Barents sea.\u0000 This study clearly demonstrates how a data-driven approach combined with machine learning algorithms can provide hidden patterns of not only LOP itself but also the additional information about the lithology, the stress history and the geographical frequency of exploration.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90813469","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}
W. Hsu, R. Litton, Haritha Vasala, D. Anderson, R. Sheppard
As the offshore wind industry matures and projects begin to expand to deeper water regions, various floating systems are being considered to support wind turbines. This paper explores the feasibility of a Tension Leg Platform (TLP) support system anchored with synthetic rope tendons attached to a gravity base template to provide a platform for a wide range of water depths with acceptable operating nacelle accelerations. In this paper, the NREL 5MW wind turbine is selected in order to provide a comparison to previous studies of steel tendon TLPs. A fully-coupled numerical modeling tool is used to assess the effects of extreme irregular sea loads on the TLP. A series of numerical simulations are carried out to compare the response of a Single Column (SC) TLP for three different water depths and three different environments. The responses are compared with the steel tendon model. The use of synthetic rope tendons potentially offers more efficient installation options and enlarges the range of acceptable water depths. The use of a gravity base/suction pile foundation may improve the installation cost and schedule. The fully coupled nonlinear, time domain analysis tool used provides a unique look into the fully operating wind turbine under stable motion characteristics of the TLP.
{"title":"Beneficial Wave Motion Response for Wind Turbine Support TLPs with Synthetic Rope Tendons","authors":"W. Hsu, R. Litton, Haritha Vasala, D. Anderson, R. Sheppard","doi":"10.4043/29573-MS","DOIUrl":"https://doi.org/10.4043/29573-MS","url":null,"abstract":"\u0000 As the offshore wind industry matures and projects begin to expand to deeper water regions, various floating systems are being considered to support wind turbines. This paper explores the feasibility of a Tension Leg Platform (TLP) support system anchored with synthetic rope tendons attached to a gravity base template to provide a platform for a wide range of water depths with acceptable operating nacelle accelerations.\u0000 In this paper, the NREL 5MW wind turbine is selected in order to provide a comparison to previous studies of steel tendon TLPs. A fully-coupled numerical modeling tool is used to assess the effects of extreme irregular sea loads on the TLP. A series of numerical simulations are carried out to compare the response of a Single Column (SC) TLP for three different water depths and three different environments. The responses are compared with the steel tendon model.\u0000 The use of synthetic rope tendons potentially offers more efficient installation options and enlarges the range of acceptable water depths. The use of a gravity base/suction pile foundation may improve the installation cost and schedule. The fully coupled nonlinear, time domain analysis tool used provides a unique look into the fully operating wind turbine under stable motion characteristics of the TLP.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"97 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91539786","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 increasing demand of energy efficiency, the evolution of emission regulatory and the limited investments allocation, increases the attractiveness for flexible gas valorization systems [GGFR]. Gas valorization system can be considered all the technical solution i.e process or new equipment installation that allow to use wasted gas sources to produce electricity of mechanical power for different application. The recovery of associated or stranded gases presents various complexities especially if applied to remote locations. For this reason, to maximize synergies with the existing premises, a flexible design and pre-assembled solutions might be recommended. This paper presents, the integration of flexible installation solutions with natural gas valorization systems. This approach is finalized to maximize the production capability of a hydrocarbon production site with a low impact on existing infrastructures and relocation possibility. On this regard, the main emphasis is placed to the following actions: The integration of flexible systems in the gas recovery processes,The upgrade of existing equipment to resolve production bottleneck,The use of mobile technology to accommodate plant flexibility. During the plant life cycle, operating conditions of some critical links of the production chain need to to be adjusted. In this case the upgrades of processes and equipment flexibility helps to prevent inefficiencies that may result in gas flow underutilization or associated gas flaring. Moderate natural gas flows, either from oil production associated products or stranded gas reserves, limits the economic viability of a gas valorization system. For this reason, solutions integrating the standard design balance of plant and the mobile truck architecture are technical choice that provide beneficial impact on the site effectiveness and economics. Moreover, mobile plants provide the further advantage to be reused in different sites through a simple relocation and minor adjustment. Offshore oil plants may not include gas boosting/offload or spare power generation solutions while small space and limited load capability generate additional complexities. In these cases, a dedicated approach like the construction of floating modular systems to be connected to the existing structure represent a viable solution.
{"title":"Smart Integration of Natural Gas Valorization Systems and Flexible Plant Installation in Existing and Low Capacity Gas Production Sites","authors":"M. Falsini, Filippo Conforti","doi":"10.4043/29551-MS","DOIUrl":"https://doi.org/10.4043/29551-MS","url":null,"abstract":"\u0000 The increasing demand of energy efficiency, the evolution of emission regulatory and the limited investments allocation, increases the attractiveness for flexible gas valorization systems [GGFR]. Gas valorization system can be considered all the technical solution i.e process or new equipment installation that allow to use wasted gas sources to produce electricity of mechanical power for different application.\u0000 The recovery of associated or stranded gases presents various complexities especially if applied to remote locations. For this reason, to maximize synergies with the existing premises, a flexible design and pre-assembled solutions might be recommended.\u0000 This paper presents, the integration of flexible installation solutions with natural gas valorization systems. This approach is finalized to maximize the production capability of a hydrocarbon production site with a low impact on existing infrastructures and relocation possibility.\u0000 On this regard, the main emphasis is placed to the following actions: The integration of flexible systems in the gas recovery processes,The upgrade of existing equipment to resolve production bottleneck,The use of mobile technology to accommodate plant flexibility.\u0000 During the plant life cycle, operating conditions of some critical links of the production chain need to to be adjusted. In this case the upgrades of processes and equipment flexibility helps to prevent inefficiencies that may result in gas flow underutilization or associated gas flaring.\u0000 Moderate natural gas flows, either from oil production associated products or stranded gas reserves, limits the economic viability of a gas valorization system. For this reason, solutions integrating the standard design balance of plant and the mobile truck architecture are technical choice that provide beneficial impact on the site effectiveness and economics. Moreover, mobile plants provide the further advantage to be reused in different sites through a simple relocation and minor adjustment.\u0000 Offshore oil plants may not include gas boosting/offload or spare power generation solutions while small space and limited load capability generate additional complexities. In these cases, a dedicated approach like the construction of floating modular systems to be connected to the existing structure represent a viable solution.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87263878","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}
Total E&P has developed for its fields an integrated workflow to assess the 2G&R uncertainties which provides a Resource evaluation distribution through the integrated Geoscience platform. If the uncertainty study also considers the operational limitations by integrating them in the modeling process, the reliability of the outputs is clearly improved. The objective of this study was to provide an evaluation of In-Place and Resource on a deep-offshore discovery located in the Gulf of Mexico while assessing not only the multiple Geoscience uncertainties but also capturing the operational constraints identified for this future development. The discovery, located under a salt canopy with a thickness up to 18’000 feet, had limitation from seismic imaging for the field interpretation. The well penetrations proved that the reservoir was highly compartmentalized and most of the faults were not seen on seismic. On top of this lateral disconnection, for each of the compartments the fluid contact depends on the structural horizons which are, on their turn, uncertain. The bulk of the information comes from few appraisal wells. Last but not least, the completions of the future development wells should integrate the drilling and well architecture limitations. All these uncertainties and constraints were managed in an integrated workflow using a Monte-Carlo Nested Multi-Realization approach. First, the structural uncertainties impact the grid which is distorted for every realization. Second, the filling of the grid with facies and petrophysical properties is done considering global and local geostatistical uncertainties. The contacts distributions are defined for almost hundred compartments. For some of them, the contacts are defined as a function of a crest, for others – a function of a spill while both (crest and spill depths) vary with the structure from one realization to another. The dynamic uncertainties on the permeability multipliers and on the relative permeability curves are considered as well. The risk of having more active faults than seen on seismic is mitigated by randomly sealing additional faults. The modeling chain also takes into account the completion limitations on future development wells. The completion tally design (minimum distance between screens and total distance of the completion intervals) are tailored to every realization in an automatic manner. The novelty of this work is that the different sources of uncertainties and the operational constraints are not modeled in separated workflows (e.g.: geophysics + geology + dynamic + completion design) but included in a single automatic process while parametrizing their complex dependencies. Thus, the eventual interactions and non-linear effects of a combination of all parameters can be anticipated, therefore providing a more accurate evaluation for decision making and development options.
总勘探开发的领域集成的工作流来评估2 g r的不确定性提供了资源评价分布通过综合地球科学平台。如果不确定性研究在建模过程中也考虑到操作限制，则输出的可靠性明显提高。本研究的目的是对墨西哥湾深海发现的就地和资源进行评估，同时不仅评估多种地球科学不确定性，而且还捕获了为未来开发确定的操作限制。该发现位于厚度达1.8万英尺的盐层下，地震成像对现场解释有限制。井侵证明储层分区化程度高，大部分断层在地震上未被发现。在这种横向分离的顶部，对于每个隔室，流体接触取决于构造层位，而构造层位又是不确定的。大部分信息来自少数几口评价井。最后但并非最不重要的是，未来开发井的完井应结合钻井和井结构的限制。利用蒙特卡罗嵌套多实现方法，将所有这些不确定性和约束管理在一个集成工作流中。首先，结构的不确定性会影响网格，网格在每一次实现中都是扭曲的。其次，考虑到全球和局部地统计的不确定性，对网格进行相和岩石物理性质的填充。触点分布被定义为近100个隔室。对于其中的一些，接触被定义为波峰的函数，而对于另一些，则是泄漏的函数，而两者(波峰和泄漏深度)都随着结构的不同而变化。同时考虑了渗透率乘数和相对渗透率曲线的动态不确定性。通过随机封闭额外的断层，可以减少比地震中看到的更活跃断层的风险。建模链还考虑了未来开发井的完井限制。完井计数设计(筛管之间的最小距离和完井间隔的总距离)以自动方式为每个实现量身定制。这项工作的新颖之处在于，不同的不确定性来源和操作约束没有在单独的工作流程中建模(例如:地球物理+地质+动态+完井设计)，而是包含在一个自动化过程中，同时参数化它们复杂的依赖关系。因此，可以预测所有参数组合的最终相互作用和非线性影响，从而为决策和发展备选办法提供更准确的评价。
{"title":"Integrated Uncertainty Study for Resources Evaluation Under Operational Constraints","authors":"T. Chugunova, M. Trani, N. Shchukina","doi":"10.4043/29502-MS","DOIUrl":"https://doi.org/10.4043/29502-MS","url":null,"abstract":"\u0000 Total E&P has developed for its fields an integrated workflow to assess the 2G&R uncertainties which provides a Resource evaluation distribution through the integrated Geoscience platform. If the uncertainty study also considers the operational limitations by integrating them in the modeling process, the reliability of the outputs is clearly improved. The objective of this study was to provide an evaluation of In-Place and Resource on a deep-offshore discovery located in the Gulf of Mexico while assessing not only the multiple Geoscience uncertainties but also capturing the operational constraints identified for this future development.\u0000 The discovery, located under a salt canopy with a thickness up to 18’000 feet, had limitation from seismic imaging for the field interpretation. The well penetrations proved that the reservoir was highly compartmentalized and most of the faults were not seen on seismic. On top of this lateral disconnection, for each of the compartments the fluid contact depends on the structural horizons which are, on their turn, uncertain. The bulk of the information comes from few appraisal wells. Last but not least, the completions of the future development wells should integrate the drilling and well architecture limitations.\u0000 All these uncertainties and constraints were managed in an integrated workflow using a Monte-Carlo Nested Multi-Realization approach. First, the structural uncertainties impact the grid which is distorted for every realization. Second, the filling of the grid with facies and petrophysical properties is done considering global and local geostatistical uncertainties. The contacts distributions are defined for almost hundred compartments. For some of them, the contacts are defined as a function of a crest, for others – a function of a spill while both (crest and spill depths) vary with the structure from one realization to another. The dynamic uncertainties on the permeability multipliers and on the relative permeability curves are considered as well. The risk of having more active faults than seen on seismic is mitigated by randomly sealing additional faults. The modeling chain also takes into account the completion limitations on future development wells. The completion tally design (minimum distance between screens and total distance of the completion intervals) are tailored to every realization in an automatic manner.\u0000 The novelty of this work is that the different sources of uncertainties and the operational constraints are not modeled in separated workflows (e.g.: geophysics + geology + dynamic + completion design) but included in a single automatic process while parametrizing their complex dependencies. Thus, the eventual interactions and non-linear effects of a combination of all parameters can be anticipated, therefore providing a more accurate evaluation for decision making and development options.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"322 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79710542","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}
Subsea deep-water oil and gas developments are characterized by the need for long term planning and large capital allocation with delayed returns. Reduced time to first oil dramatically improves field economics and enables the efficient application of capital. Shorter project durations can be achieved by implementing a phased approach to field development. Phased developments allow for reduced upfront Capital Expenditure (CAPEX) and moderate returns, followed by the future investment from earned revenues to expand the field. The result can be dramatically improved capital efficiency, substantially reduced financial exposure and maximized utilization of common production facilities across the life of the field. Each subsequent phase can become technically more challenging, as offsets become longer, and reservoir properties begin to differ from those of the initial production fluids. This paper provides an overview of the technologies that can be deployed for such a phased development approach, ultimately enabling the economic exploitation of long tie-backs and discusses the status of the required technologies.
{"title":"Subsea Long-Distance Tie-Back","authors":"D. Wiles, E. Widjaja, J. Davalath","doi":"10.4043/29319-MS","DOIUrl":"https://doi.org/10.4043/29319-MS","url":null,"abstract":"\u0000 Subsea deep-water oil and gas developments are characterized by the need for long term planning and large capital allocation with delayed returns. Reduced time to first oil dramatically improves field economics and enables the efficient application of capital. Shorter project durations can be achieved by implementing a phased approach to field development. Phased developments allow for reduced upfront Capital Expenditure (CAPEX) and moderate returns, followed by the future investment from earned revenues to expand the field. The result can be dramatically improved capital efficiency, substantially reduced financial exposure and maximized utilization of common production facilities across the life of the field. Each subsequent phase can become technically more challenging, as offsets become longer, and reservoir properties begin to differ from those of the initial production fluids. This paper provides an overview of the technologies that can be deployed for such a phased development approach, ultimately enabling the economic exploitation of long tie-backs and discusses the status of the required technologies.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81945379","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}
Kaikias is an oil discovery of four stacked miocene reservoirs in the Deepwater Gulf of Mexico in the Greater Mars/Ursa Area. During exploration, only the lowest reservoir objective (Lambda) was penetrated, discovering oil pay to base. A follow-up appraisal well was drilled penetrating the upper three reservoir objectives (Beta, Zeta, and Kappa) discovering oil pay to base in all reservoirs, as well as penetrating the lowest reservoir objective (Lambda) and again discovering oil pay to base. Following the exploration and appraisal program, there remained considerable resource uncertainty given the lack of definitive oil water contacts in any of the reservoirs and poor seismic imaging (impacting the ability to determine the reservoir extent and thickness). Rather than continue to de-risk the field with further exploration and appraisal activities (potentially eroding lifecycle value and delaying first oil), a small, robust Phase 1 project was matured to accelerate first oil and to de-risk the subsurface through production data. The Phase 1 project was highly competitive attributable to the re-use of two existing exploration and appraisal wellbores and a minimal subsea scope. The Phase 1 project was sanctioned by Shell (80%) and MOEX NA (20%) in January 2017. During execution of Phase 1, a Phase 2 project was proposed to further appraise the three reservoirs developed by Phase 1 (Beta, Kappa, and Lambda) as well as to produce unique volumes from the fourth reservoir (Zeta). The Phase 2 appraisal program was a great success, proving upside in all three Phase 1 reservoirs and justifying expansion of the two lowest reservoirs (Kappa and Lambda). Following the successful Phase 2 appraisal and subsequent side track to the Zeta reservoir, a Phase 3 project was proposed to add a second production well to each of the two lowest reservoirs, accelerating and capturing unique volumes from each. The Phase 3 project also provided an opportunity to calibrate seismic imaging for further exploration in the area and to provide a better understanding of fluid gradients. This phased appraisal and development approach resulted in a highly a competitive investment for Shell (80%) and MOEX NA (20%) and allowed co-owners to optimize the lifecycle value of the project without overspending on exploration and appraisal activities. Further, the phased appraisal and development approach reduced the overall downside risk for the project.
{"title":"Kaikias Phased Appraisal and Development Strategy","authors":"Scott C Hyder, John Baird","doi":"10.4043/29538-MS","DOIUrl":"https://doi.org/10.4043/29538-MS","url":null,"abstract":"\u0000 Kaikias is an oil discovery of four stacked miocene reservoirs in the Deepwater Gulf of Mexico in the Greater Mars/Ursa Area. During exploration, only the lowest reservoir objective (Lambda) was penetrated, discovering oil pay to base. A follow-up appraisal well was drilled penetrating the upper three reservoir objectives (Beta, Zeta, and Kappa) discovering oil pay to base in all reservoirs, as well as penetrating the lowest reservoir objective (Lambda) and again discovering oil pay to base. Following the exploration and appraisal program, there remained considerable resource uncertainty given the lack of definitive oil water contacts in any of the reservoirs and poor seismic imaging (impacting the ability to determine the reservoir extent and thickness). Rather than continue to de-risk the field with further exploration and appraisal activities (potentially eroding lifecycle value and delaying first oil), a small, robust Phase 1 project was matured to accelerate first oil and to de-risk the subsurface through production data. The Phase 1 project was highly competitive attributable to the re-use of two existing exploration and appraisal wellbores and a minimal subsea scope. The Phase 1 project was sanctioned by Shell (80%) and MOEX NA (20%) in January 2017.\u0000 During execution of Phase 1, a Phase 2 project was proposed to further appraise the three reservoirs developed by Phase 1 (Beta, Kappa, and Lambda) as well as to produce unique volumes from the fourth reservoir (Zeta). The Phase 2 appraisal program was a great success, proving upside in all three Phase 1 reservoirs and justifying expansion of the two lowest reservoirs (Kappa and Lambda). Following the successful Phase 2 appraisal and subsequent side track to the Zeta reservoir, a Phase 3 project was proposed to add a second production well to each of the two lowest reservoirs, accelerating and capturing unique volumes from each. The Phase 3 project also provided an opportunity to calibrate seismic imaging for further exploration in the area and to provide a better understanding of fluid gradients. This phased appraisal and development approach resulted in a highly a competitive investment for Shell (80%) and MOEX NA (20%) and allowed co-owners to optimize the lifecycle value of the project without overspending on exploration and appraisal activities. Further, the phased appraisal and development approach reduced the overall downside risk for the project.","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":"84951414","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 ærfugl field is a gas condensate field located in the Norwegian Sea to the West of Skarv and Idun fields. The first phase consisting of well 4, 5 and 6 is planned to be developed with three off single slot templates as a 20 km long tie-back to the Aker BP operated Skarv FPSO connected to existing subsea infrastructure. The field layout can be seen in Heat input into the flow line system is required during shut down and potentially also during off-plateau production periods. A new enabling technology Electrically Heat Traced Flowline (EHTF) will be utilised to enable system start-up and shut down, and to maintain the production fluids outside of the hydrate envelope during steady state operation. The EHTF system is developed by Subsea 7 and ITP InTerPipe. The ærfugl EHTF system consists of an electrically heated 10" flowline inside a 16" carrier pipe (Pipe in Pipe). The large annulus between the 10" and the 16" allows for good insulation, and combined with reduced annulus pressure, a U-value of less than 0.5 W/m/K is achieved. Such a low U-value allows for a more passive system where only limited power is required for heating. The ærfugl EHTF system is based on a topside transformer. The power cables go directly from a topside bus bar via a dynamic and static power umbilical system to the In-Line Power Inlet Structure (ILPISTM) on the Electrically Heat Traced Flowline (EHTF). There is as such not any sophisticated subsea components to transform or split the current. All components that may need maintenance and repair are located topside. This gives a high availability and reliability of the subsea system. The EHTF technology is new. As such, we have limited literature on this technology. The paper will present how the EHTF technology works, and describes how it is set up for the ærfugl field. The information provided in this paper can be used as input to evaluate if EHTF should be considered in developments of new fields. This is especially relevant for fields with challenging flow assurance, such as long tie-backs.
{"title":"New Technology Enables Development of Field in Norwegian Sea","authors":"Arne Skeie","doi":"10.4043/29523-MS","DOIUrl":"https://doi.org/10.4043/29523-MS","url":null,"abstract":"\u0000 The ærfugl field is a gas condensate field located in the Norwegian Sea to the West of Skarv and Idun fields. The first phase consisting of well 4, 5 and 6 is planned to be developed with three off single slot templates as a 20 km long tie-back to the Aker BP operated Skarv FPSO connected to existing subsea infrastructure. The field layout can be seen in\u0000 Heat input into the flow line system is required during shut down and potentially also during off-plateau production periods. A new enabling technology Electrically Heat Traced Flowline (EHTF) will be utilised to enable system start-up and shut down, and to maintain the production fluids outside of the hydrate envelope during steady state operation. The EHTF system is developed by Subsea 7 and ITP InTerPipe.\u0000 The ærfugl EHTF system consists of an electrically heated 10\" flowline inside a 16\" carrier pipe (Pipe in Pipe). The large annulus between the 10\" and the 16\" allows for good insulation, and combined with reduced annulus pressure, a U-value of less than 0.5 W/m/K is achieved. Such a low U-value allows for a more passive system where only limited power is required for heating.\u0000 The ærfugl EHTF system is based on a topside transformer. The power cables go directly from a topside bus bar via a dynamic and static power umbilical system to the In-Line Power Inlet Structure (ILPISTM) on the Electrically Heat Traced Flowline (EHTF). There is as such not any sophisticated subsea components to transform or split the current. All components that may need maintenance and repair are located topside. This gives a high availability and reliability of the subsea system.\u0000 The EHTF technology is new. As such, we have limited literature on this technology. The paper will present how the EHTF technology works, and describes how it is set up for the ærfugl field.\u0000 The information provided in this paper can be used as input to evaluate if EHTF should be considered in developments of new fields. This is especially relevant for fields with challenging flow assurance, such as long tie-backs.","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":"83271160","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}
T. Williams, R. Haut, John H. Cohen, James Pettigrew
Investments in applied research have made positive improvements in safety and environmental protection in the oil and gas industry. This paper identifies technical needs, research topics and processes for future research investments in the Gulf of Mexico based on a report titled "21st Century Ocean Energy Safety Research Roadmap" (Roadmap). This report was completed by RPSEA for the Ocean Energy Safety Institute (OESI) in November 2018. Funding for OESI and this report came from the U.S. Department of Interior Bureau of Safety and Environmental Enforcement (BSEE). This paper provides an overview of the report findings as well as a summary of areas where the government, key stakeholders and industry can work together to continue to improve safety and environmental improvement. Investments in safety and environmentally protective research are responsibility of all parties. This report stresses that new technologies are of little value if they cannot be applied, so the process of how the research is conducted, early stage adoption, advancements and technology transfer play a key role. It is important to note that as new technologies are developed, the personnel qualifications may also change, as will associated training. The Roadmap, developed in this effort, offers a unique opportunity to guide the applications of advanced technologies. These new technology applications will continue the significant progress of current safety and environmental management systems and procedures. The recommendations were based on areas where government funding and leadership can play an important role. These recommendations came from workshops, interviews of subject matter experts, surveys, and an extensive literature search. Prior recommendations are also included from reports published by the Society of Petroleum Engineers, the Gulf Research Program, the Center for Offshore Safety, OESI and RPSEA. Investments in safety and environmental research spiked following the Macondo incident, as they have following prior safety and environmental incidences. Most of the research funding has come from fines and penalties, (from the RESTORE Act), but other substantial funding has come from industry. The offshore oil and gas industry have made significant progress in developing safety and environmental management systems and procedures. These systems and processes provide an opportunity to incorporate advances in technology for continued improvements. Working with regulators, service providers and researchers, this document addresses an important need to identify and prioritize limited research investments. The goal is for identified R&D investments to target the development of safe, environmentally sensitive, cost-effective technologies. The application of these advances will allow industry to develop resources in increasingly challenging conditions and ensure that the understanding of the risks associated with operations will keep pace with the technologies that indust
{"title":"21st Century Ocean Energy Safety Research Roadmap","authors":"T. Williams, R. Haut, John H. Cohen, James Pettigrew","doi":"10.4043/29650-MS","DOIUrl":"https://doi.org/10.4043/29650-MS","url":null,"abstract":"\u0000 Investments in applied research have made positive improvements in safety and environmental protection in the oil and gas industry. This paper identifies technical needs, research topics and processes for future research investments in the Gulf of Mexico based on a report titled \"21st Century Ocean Energy Safety Research Roadmap\" (Roadmap). This report was completed by RPSEA for the Ocean Energy Safety Institute (OESI) in November 2018. Funding for OESI and this report came from the U.S. Department of Interior Bureau of Safety and Environmental Enforcement (BSEE). This paper provides an overview of the report findings as well as a summary of areas where the government, key stakeholders and industry can work together to continue to improve safety and environmental improvement.\u0000 Investments in safety and environmentally protective research are responsibility of all parties. This report stresses that new technologies are of little value if they cannot be applied, so the process of how the research is conducted, early stage adoption, advancements and technology transfer play a key role. It is important to note that as new technologies are developed, the personnel qualifications may also change, as will associated training. The Roadmap, developed in this effort, offers a unique opportunity to guide the applications of advanced technologies. These new technology applications will continue the significant progress of current safety and environmental management systems and procedures.\u0000 The recommendations were based on areas where government funding and leadership can play an important role. These recommendations came from workshops, interviews of subject matter experts, surveys, and an extensive literature search. Prior recommendations are also included from reports published by the Society of Petroleum Engineers, the Gulf Research Program, the Center for Offshore Safety, OESI and RPSEA.\u0000 Investments in safety and environmental research spiked following the Macondo incident, as they have following prior safety and environmental incidences. Most of the research funding has come from fines and penalties, (from the RESTORE Act), but other substantial funding has come from industry.\u0000 The offshore oil and gas industry have made significant progress in developing safety and environmental management systems and procedures. These systems and processes provide an opportunity to incorporate advances in technology for continued improvements. Working with regulators, service providers and researchers, this document addresses an important need to identify and prioritize limited research investments.\u0000 The goal is for identified R&D investments to target the development of safe, environmentally sensitive, cost-effective technologies. The application of these advances will allow industry to develop resources in increasingly challenging conditions and ensure that the understanding of the risks associated with operations will keep pace with the technologies that indust","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"55 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83816456","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A normally un-manned minimal floating platform can be used for several applications to support subsea development. The applications include enabling Long Subsea Tiebacks by supporting power generation and distribution equipment, when the host facility doesn't have excess power capacity (Power Buoy) or the required footprint and space to support the required power distribution hardware or locate the distribution equipment to distribute the power imported from shore. It can also serve as a partial processing host with functionality ranging from Chemicals and Artificial Lift all the way to Multi-Phase Pumping or Gas Compression, as required. An un-manned floating platform can be a cost-efficient solution, where the economics of a very Long Subsea Tieback or a Host Facility with full processing capacity become prohibitive for developing small to medium size fields. The substructures for these platforms have reduced and simplified systems resulting in lower Capex, Opex and minimal maintenance requirements. This platform is safer to operate than conventional host platforms because it is un-manned, and it also deploys robotics and remotely controlled equipment, using the latest advances in digital, robotics, and autonomous control technologies. The paper reviews the different floating unmanned minimal platform configurations that are designed for this purpose. The following aspects of the normally un-manned floating platform are discussed: Functionality Cost-Efficient Design alternatives Construction/Installation efficiency Operations/ Maintenance principles Possible applications of the normally un-manned floating platform include small to medium size fields, remote gas fields requiring compression to export gas to shore that would otherwise prove to be un-economical to develop. The normally un-manned floating platform helps improve the development economics and the operational safety of these fields. The industry's response to the oil price slump in the past few years combined with the latest advances in technology led to the evolution of these minimal unmanned floating platforms.
{"title":"Un-Manned Minimal Floating Platforms","authors":"E. Beyko, A. Sablok, M. Pegg","doi":"10.4043/29648-MS","DOIUrl":"https://doi.org/10.4043/29648-MS","url":null,"abstract":"\u0000 A normally un-manned minimal floating platform can be used for several applications to support subsea development. The applications include enabling Long Subsea Tiebacks by supporting power generation and distribution equipment, when the host facility doesn't have excess power capacity (Power Buoy) or the required footprint and space to support the required power distribution hardware or locate the distribution equipment to distribute the power imported from shore. It can also serve as a partial processing host with functionality ranging from Chemicals and Artificial Lift all the way to Multi-Phase Pumping or Gas Compression, as required.\u0000 An un-manned floating platform can be a cost-efficient solution, where the economics of a very Long Subsea Tieback or a Host Facility with full processing capacity become prohibitive for developing small to medium size fields. The substructures for these platforms have reduced and simplified systems resulting in lower Capex, Opex and minimal maintenance requirements. This platform is safer to operate than conventional host platforms because it is un-manned, and it also deploys robotics and remotely controlled equipment, using the latest advances in digital, robotics, and autonomous control technologies.\u0000 The paper reviews the different floating unmanned minimal platform configurations that are designed for this purpose. The following aspects of the normally un-manned floating platform are discussed:\u0000 Functionality Cost-Efficient Design alternatives Construction/Installation efficiency Operations/ Maintenance principles\u0000 Possible applications of the normally un-manned floating platform include small to medium size fields, remote gas fields requiring compression to export gas to shore that would otherwise prove to be un-economical to develop. The normally un-manned floating platform helps improve the development economics and the operational safety of these fields. The industry's response to the oil price slump in the past few years combined with the latest advances in technology led to the evolution of these minimal unmanned floating platforms.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88037825","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper describes improvements to the methods for verification of process safety design requirements in an Oil & Gas (O&G) project and highlights the benefits of standardized verification linked to design requirements. The similarities and benefits of verification activities used in aerospace/NASA projects are also discussed. The team identified and documented the activities that should be performed by a project throughout the project life cycle to verify compliance with process safety requirements. These verification activities were tied to existing project deliverables and controls where possible. Focusing on verification in the design stage (analyze, calculate, review) in preference to final execution (inspect, certify) enables earlier identification of problems, earlier intervention, and increases confidence that the process safety requirements have been met. While this approach may be new in the O&G industry, the aerospace community has used similar methods for decades. Verification within aerospace/NASA involves design phase verification and product (final) verification. Initial verification is done to show that: 1) the design is realizable, 2) requirements are acceptable and have bidirectional traceability to higher-level requirements and stakeholder expectations, and 3) the design solution is consistent with requirement statements and constraints. Conducting the initial verification through peer/design reviews improves compliance to requirements at the final product verification. By establishing the traceability during the initial verification, database links are established and then just need to be populated with the final verification reports for closure. During verification activities, identification of critical systems and safety hazard controls are introduced and considered to influence the design and eventually become part of the verification evidence. Projects select pre-identified verification activities, which will then be used to generate an executable plan. The plan is used to sort/filter the statements and allocate them to the right scope elements and party to provide verification. Standardizing verification eliminates engineering hours for engineering contractors and suppliers. Completed verification plans increase company knowledge regarding requirement implementation, making the next project more efficient to execute. There is increased visibility of where the supply chain is supporting the process safety requirements. For the first time, the supply chain will confirm they have implemented the requirements and provide feedback on the clarity of the requirements. Clear confirmation that process safety requirements have been verified will drive improved safety performance. This paper provides a new approach in O&G for identifying process safety requirements and linking these requirements to standardized verification methods. Specific examples will be shared to show the similarities of the verific
{"title":"Verifying Process Safety Requirements: Similarities Between Aerospace and Oil & Gas Industries","authors":"Mia Zager, Anne McKinney, M. Reed, Kevin Orr","doi":"10.4043/29295-MS","DOIUrl":"https://doi.org/10.4043/29295-MS","url":null,"abstract":"\u0000 \u0000 \u0000 This paper describes improvements to the methods for verification of process safety design requirements in an Oil & Gas (O&G) project and highlights the benefits of standardized verification linked to design requirements. The similarities and benefits of verification activities used in aerospace/NASA projects are also discussed.\u0000 \u0000 \u0000 \u0000 The team identified and documented the activities that should be performed by a project throughout the project life cycle to verify compliance with process safety requirements. These verification activities were tied to existing project deliverables and controls where possible. Focusing on verification in the design stage (analyze, calculate, review) in preference to final execution (inspect, certify) enables earlier identification of problems, earlier intervention, and increases confidence that the process safety requirements have been met. While this approach may be new in the O&G industry, the aerospace community has used similar methods for decades. Verification within aerospace/NASA involves design phase verification and product (final) verification. Initial verification is done to show that: 1) the design is realizable, 2) requirements are acceptable and have bidirectional traceability to higher-level requirements and stakeholder expectations, and 3) the design solution is consistent with requirement statements and constraints. Conducting the initial verification through peer/design reviews improves compliance to requirements at the final product verification. By establishing the traceability during the initial verification, database links are established and then just need to be populated with the final verification reports for closure. During verification activities, identification of critical systems and safety hazard controls are introduced and considered to influence the design and eventually become part of the verification evidence.\u0000 \u0000 \u0000 \u0000 Projects select pre-identified verification activities, which will then be used to generate an executable plan. The plan is used to sort/filter the statements and allocate them to the right scope elements and party to provide verification. Standardizing verification eliminates engineering hours for engineering contractors and suppliers. Completed verification plans increase company knowledge regarding requirement implementation, making the next project more efficient to execute. There is increased visibility of where the supply chain is supporting the process safety requirements. For the first time, the supply chain will confirm they have implemented the requirements and provide feedback on the clarity of the requirements. Clear confirmation that process safety requirements have been verified will drive improved safety performance.\u0000 \u0000 \u0000 \u0000 This paper provides a new approach in O&G for identifying process safety requirements and linking these requirements to standardized verification methods. Specific examples will be shared to show the similarities of the verific","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88100253","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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