The rapid expansion of the Australian gas industry has seen massive investment in mega-projects, but benefits from this have been impeded by the impact of severe project delays. Risks causing delays in upstream mega-projects are high, leading to frequent cost and schedule overruns. However, the absence of research concerning delays during this complex phase of mega-projects provides the opportunity to critically examine underlying challenges experienced by various project participants involved in upstream gas projects in Australia. Data was gathered through an extensive literature review, interviews with industry experts, and a survey. A list of risk factors extracted from the literature was checked with industry experts for relevance in upstream mega-projects, and missing risks were added. The survey was circulated to a random sample of people working within the natural gas projects domain, including clients, consultants, and contractor organisations. Using Likert-style five-point scales, participants rated the frequency of occurrence and severity of each of the risks impacting delays. A total of 70 risk factors were identified, which were then traced back to 10 risk sources that impact delays in upstream gas projects. The findings reveal that 72% of participants believe that the average delay in gas projects is between 10% and 30% in Australia. Moreover, 93% of participants mentioned that schedule slippage in the upstream phase causes severe challenges in attaining "first gas" and results in overall project delays. Based on the frequency of occurrence and severity indices, the magnitude of risk factors and sources was used to ascertain critical risks causing major delays. Kruskal-Wallis and Mann-Whitney U tests were applied to check the differences in perception of risk criticality influencing delays among the participants, who differed depending on work experience, job position, and the type of participants’ company. These tests indicated a good association in such perceptions. Key risk factors causing major delays included frequent change orders being issued by clients, unrealistic time schedules imposed on contracts, and poor organisational structures. Risks in mega-projects cannot be eliminated completely. However, a more precise identification and prioritisation of risks causing major delays, along with differences in risk perceptions of various project parties, will provide an informed and broader perspective to industry practitioners and stakeholders in managing risks more effectively to reduce upstream gas project delays.
{"title":"Risk Factors Affecting Delays in Upstream Natural Gas Mega-Projects: An Australian Perspective","authors":"Munmun Basak, V. Coffey, Robert K. Perrons","doi":"10.2118/192095-MS","DOIUrl":"https://doi.org/10.2118/192095-MS","url":null,"abstract":"\u0000 The rapid expansion of the Australian gas industry has seen massive investment in mega-projects, but benefits from this have been impeded by the impact of severe project delays. Risks causing delays in upstream mega-projects are high, leading to frequent cost and schedule overruns. However, the absence of research concerning delays during this complex phase of mega-projects provides the opportunity to critically examine underlying challenges experienced by various project participants involved in upstream gas projects in Australia.\u0000 Data was gathered through an extensive literature review, interviews with industry experts, and a survey. A list of risk factors extracted from the literature was checked with industry experts for relevance in upstream mega-projects, and missing risks were added. The survey was circulated to a random sample of people working within the natural gas projects domain, including clients, consultants, and contractor organisations. Using Likert-style five-point scales, participants rated the frequency of occurrence and severity of each of the risks impacting delays.\u0000 A total of 70 risk factors were identified, which were then traced back to 10 risk sources that impact delays in upstream gas projects. The findings reveal that 72% of participants believe that the average delay in gas projects is between 10% and 30% in Australia. Moreover, 93% of participants mentioned that schedule slippage in the upstream phase causes severe challenges in attaining \"first gas\" and results in overall project delays. Based on the frequency of occurrence and severity indices, the magnitude of risk factors and sources was used to ascertain critical risks causing major delays. Kruskal-Wallis and Mann-Whitney U tests were applied to check the differences in perception of risk criticality influencing delays among the participants, who differed depending on work experience, job position, and the type of participants’ company. These tests indicated a good association in such perceptions. Key risk factors causing major delays included frequent change orders being issued by clients, unrealistic time schedules imposed on contracts, and poor organisational structures.\u0000 Risks in mega-projects cannot be eliminated completely. However, a more precise identification and prioritisation of risks causing major delays, along with differences in risk perceptions of various project parties, will provide an informed and broader perspective to industry practitioners and stakeholders in managing risks more effectively to reduce upstream gas project delays.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82527457","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}
Mingzhan Chen, Jiecheng Cheng, Zhou Wanfu, Youquan Huang, Xiaoming Sun, G. Cao, S. Han, Wang Guoqing, Tao Jiang, Ping Li, Yanyan Wang
Scaling issue of artificial lift systems is the main bottleneck for ASP flooding, and has considerably negative influence in commercial stage. In the past decade, different anti-scaling technologies have been developed and applied in Daqing Oilfield. However, high pump failure still exists in severely scaling producers. This paper presents an innovative artificial lift method – a patented bailing pumping unit production system, which has been applied successfully in field test stage in Daqing Oilfield. The system consists of soft plunger, special designed wire line, winch system and surface control. Produced liquid mixed with large quantity of scale particles is lifted to surface by the soft plunger connected to wire line. The plunger is made of high molecular materials and steel skeleton support which ensures good flexibility and reliability after long term of operation in abrasive environment. The wire line is specified designed and processed to enhance operation life. It connects downhole gauge and surface control. Down hole pressure can be monitored in real time, which provides references for adjustment. This innovative bailing pumping unit production system has been applied in 80 wells in 3 ASP flooding blocks with severe scaling issue in Daqing Oilfield. The average running life was improved from several weeks to 710 days. Considerable benefits have been achieved by the 60% operation cost decline. It has been the premier artificial lift method for the severely scaling producers. Additionally, there is no need for flushing or acidizing treatment to deal with scale deposited in downhole pump, rod string, and tubing string compared with pumping unit production system in ASP flooding, which significantly reduces normal management intensity and cost. Field test showed that this innovative bailing pumping unit production system has outstanding scale resistance capability for severe scaling wells in ASP flooding. It also provides a great reference for other oilfields in worldwide with similar issues both in ASP flooding and high salinity conditions.
{"title":"An Innovative Artificial Lift Technology for Severely Scaling Wells Applied Successfully in Asp Flooding in Daqing Oilfield","authors":"Mingzhan Chen, Jiecheng Cheng, Zhou Wanfu, Youquan Huang, Xiaoming Sun, G. Cao, S. Han, Wang Guoqing, Tao Jiang, Ping Li, Yanyan Wang","doi":"10.2118/192121-MS","DOIUrl":"https://doi.org/10.2118/192121-MS","url":null,"abstract":"\u0000 Scaling issue of artificial lift systems is the main bottleneck for ASP flooding, and has considerably negative influence in commercial stage. In the past decade, different anti-scaling technologies have been developed and applied in Daqing Oilfield. However, high pump failure still exists in severely scaling producers. This paper presents an innovative artificial lift method – a patented bailing pumping unit production system, which has been applied successfully in field test stage in Daqing Oilfield.\u0000 The system consists of soft plunger, special designed wire line, winch system and surface control. Produced liquid mixed with large quantity of scale particles is lifted to surface by the soft plunger connected to wire line. The plunger is made of high molecular materials and steel skeleton support which ensures good flexibility and reliability after long term of operation in abrasive environment. The wire line is specified designed and processed to enhance operation life. It connects downhole gauge and surface control. Down hole pressure can be monitored in real time, which provides references for adjustment.\u0000 This innovative bailing pumping unit production system has been applied in 80 wells in 3 ASP flooding blocks with severe scaling issue in Daqing Oilfield. The average running life was improved from several weeks to 710 days. Considerable benefits have been achieved by the 60% operation cost decline. It has been the premier artificial lift method for the severely scaling producers. Additionally, there is no need for flushing or acidizing treatment to deal with scale deposited in downhole pump, rod string, and tubing string compared with pumping unit production system in ASP flooding, which significantly reduces normal management intensity and cost.\u0000 Field test showed that this innovative bailing pumping unit production system has outstanding scale resistance capability for severe scaling wells in ASP flooding. It also provides a great reference for other oilfields in worldwide with similar issues both in ASP flooding and high salinity conditions.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"160 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88295187","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 novel extended bowtie risk assessment methodology was used to develop the safety assessments for three Major Hazard Facilities (MHFs). Combined with an innovative risk management tool for operationalizing risk management processes, it provides a clear overview of each facility's current operational risk profile and the health of the safety critical barriers. This paper describes the bowtie methodology, its application in the development of the MHF safety assessments and the operationalization of the safety assessments through the risk management tool.
{"title":"Operationalising MHF Safety Assessments","authors":"L. Jefferies, Pamela Ooi","doi":"10.2118/191884-MS","DOIUrl":"https://doi.org/10.2118/191884-MS","url":null,"abstract":"\u0000 A novel extended bowtie risk assessment methodology was used to develop the safety assessments for three Major Hazard Facilities (MHFs). Combined with an innovative risk management tool for operationalizing risk management processes, it provides a clear overview of each facility's current operational risk profile and the health of the safety critical barriers. This paper describes the bowtie methodology, its application in the development of the MHF safety assessments and the operationalization of the safety assessments through the risk management tool.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80425561","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}
Despite decades of numerical, analytical and experimental researches, sand production remains a significant operational challenge in petroleum industry. Amongst all techniques, analytical solutions have gained more popularity in industry applications because the numerical analysis is time consuming; computationally demanding and solutions are unstable in many instances. Analytical solutions on the other hand are yet to evolve to represent the rock behaviour more accurately. We therefore developed a new set of closed-form solutions for poro-elastoplasticity with strain softening behaviour to predict stress-strain distributions around the borehole. A set of hollow cylinder experiments was then conducted under different compression scenarios and 3D X-Ray Computed Tomography was performed to analyse the internal structural damage. The results of the proposed analytical solutions were compared with the experimental results and good agreement between the model prediction and experimental data was observed. The model performance was then tested by analysing the onset of sand production in a well drilled in Bohai Bay in Northeast of China. Acoustic and density log along with core data were used to provide the input parameters for the proposed analytical model in order to predict the potential sanding in this well. The proposed solution predicted the development of a significant plastic zone thus confirming sand production observed by today sanding issue in this well.
{"title":"A Multiscale Study on The Onset of Sand Production","authors":"A. Lv, H. L. Ramandi, H. Roshan","doi":"10.2118/191881-MS","DOIUrl":"https://doi.org/10.2118/191881-MS","url":null,"abstract":"\u0000 Despite decades of numerical, analytical and experimental researches, sand production remains a significant operational challenge in petroleum industry. Amongst all techniques, analytical solutions have gained more popularity in industry applications because the numerical analysis is time consuming; computationally demanding and solutions are unstable in many instances. Analytical solutions on the other hand are yet to evolve to represent the rock behaviour more accurately.\u0000 We therefore developed a new set of closed-form solutions for poro-elastoplasticity with strain softening behaviour to predict stress-strain distributions around the borehole. A set of hollow cylinder experiments was then conducted under different compression scenarios and 3D X-Ray Computed Tomography was performed to analyse the internal structural damage. The results of the proposed analytical solutions were compared with the experimental results and good agreement between the model prediction and experimental data was observed. The model performance was then tested by analysing the onset of sand production in a well drilled in Bohai Bay in Northeast of China. Acoustic and density log along with core data were used to provide the input parameters for the proposed analytical model in order to predict the potential sanding in this well. The proposed solution predicted the development of a significant plastic zone thus confirming sand production observed by today sanding issue in this well.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75773442","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}
Vikram Sharma, J. Davies, Benjamin Vella, Jesscia Jiang, I. Sugiarto, S. Mazumder
Development of coal seam gas fields is conceptually simple but complexity arises with: the stochastic nature of coal reservoirscontinually changing work scopethe large number of wells required to meet gas contracts. In the current environment, the cost of developing thousands of wells and hundreds of kilometres of associated gathering is a key driver to the success or failure of CSG projects. Continuous reduction in cost/funding with limited resources drives companies to derive an integrated approach to the field development. Subsurface models now form an integral part of production forecasting and decision making. Companies have benefited from the computation technological advances in the recent past, whereby it is possible to run large-scale models in a reasonable timeframe. Several tools and approaches are available today to integrate complex 3D reservoir models with surface networks to generate an integrated production forecast. In this paper we focus on using advanced geospatial applications with integrated system models to derive a development concept which is optimal, realistic and capable of adapting to changes in work scope as the development progresses. Gathering routes and associated material take off (MTO) points are generated in geographic information system (GIS) tools, using constraints and criteria such as: access and approvalssub-surface data (scope of recovery maps, net coal and permeability)maximum use of existing infrastructure (Roads, Tracks, etc.)environmental constraints (overland flow, vegetation, etc.)well spacing. Seamless integration of GIS tools and sub-surface modeling tools is what makes this workflow unique. GIS tools acts as a key integrator, forcing different disciplines and departments to work together in a common platform. It also functions as a common database used across an entire organisation. GIS toolbox gives a significant head-start to the project by first defining what is achievable. It is then finessed with the best value sub-surface outcome and a final forecast is derived in a significantly shorter time scale. With the approach presented in this paper, the forecasting cycle, involving full economic run, is substantially reduced– from several months to just weeks, if not days. The final outcome is an achievable well sequence which is derived along a realistic gathering route. With this, the MTO and the production forecasts are aligned and the associated costs can be easily traced to source. This workflow is automated and can be easily repeated if scope or project premise changes. Last but not least, this approach can be applied to any onshore unconventional or conventional plays.
{"title":"Integrated Modelling Workflow for Life Cycle Development of a Large Scale Coal Seam Gas Field","authors":"Vikram Sharma, J. Davies, Benjamin Vella, Jesscia Jiang, I. Sugiarto, S. Mazumder","doi":"10.2118/191986-MS","DOIUrl":"https://doi.org/10.2118/191986-MS","url":null,"abstract":"\u0000 Development of coal seam gas fields is conceptually simple but complexity arises with: the stochastic nature of coal reservoirscontinually changing work scopethe large number of wells required to meet gas contracts.\u0000 In the current environment, the cost of developing thousands of wells and hundreds of kilometres of associated gathering is a key driver to the success or failure of CSG projects. Continuous reduction in cost/funding with limited resources drives companies to derive an integrated approach to the field development.\u0000 Subsurface models now form an integral part of production forecasting and decision making. Companies have benefited from the computation technological advances in the recent past, whereby it is possible to run large-scale models in a reasonable timeframe. Several tools and approaches are available today to integrate complex 3D reservoir models with surface networks to generate an integrated production forecast. In this paper we focus on using advanced geospatial applications with integrated system models to derive a development concept which is optimal, realistic and capable of adapting to changes in work scope as the development progresses. Gathering routes and associated material take off (MTO) points are generated in geographic information system (GIS) tools, using constraints and criteria such as: access and approvalssub-surface data (scope of recovery maps, net coal and permeability)maximum use of existing infrastructure (Roads, Tracks, etc.)environmental constraints (overland flow, vegetation, etc.)well spacing.\u0000 Seamless integration of GIS tools and sub-surface modeling tools is what makes this workflow unique. GIS tools acts as a key integrator, forcing different disciplines and departments to work together in a common platform. It also functions as a common database used across an entire organisation. GIS toolbox gives a significant head-start to the project by first defining what is achievable. It is then finessed with the best value sub-surface outcome and a final forecast is derived in a significantly shorter time scale. With the approach presented in this paper, the forecasting cycle, involving full economic run, is substantially reduced– from several months to just weeks, if not days. The final outcome is an achievable well sequence which is derived along a realistic gathering route. With this, the MTO and the production forecasts are aligned and the associated costs can be easily traced to source. This workflow is automated and can be easily repeated if scope or project premise changes. Last but not least, this approach can be applied to any onshore unconventional or conventional plays.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"38 12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78359740","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}
Xian Shi, Dongjie Li, Yuanfang Cheng, Zhongying Han, W. Fu
Fixed plane perforation technology is regarded as a good mean to address near wellbore tortuosity and reduce breakdown pressure in low permeability reservoirs. To better understand of the fracture behavior in wellbore perforations at the defining plane, a 2D finite element model has been implemented in ABAQUS to investigate the effects of mechanical, perforation and treatment parameters on hydraulic fracture propagation path. The global zero thickness cohesive elements have been inserted into numerical model, thus the existence of natural fractures on patterns of fracture propagation can be considered in this model. It shows that there is a great impact of natural fracture on the fracture propagation path. Moreover, the fracturing fluid viscosity, pumping rate, in-situ stress and perforation parameters also play critical roles on fracture propagation. Comparisons of numerical simulations show that the effects of the stress anisotropy, pumping rate, fluid viscosity, Young's modulus, Poisson's ratio and perforation intersection angle on the hydraulic fracture geometry of exterior fractures and interior fracture at the defining plane are different. It found that the width of interior fracture is almost zero at the near wellbore zone at the end of pumping which induced by the stress interference of neighboring fractures in some cases, thus perforations design at the defining plane must be carefully considered. Additionally, in most cases, hydraulic fractures from exterior perforations tend to propagate upward and downward simultaneously. Although hydraulic fractures initiated from a perforation that misaligned with the direction along the maximum in-situ stress initially at short distance, hydraulic fractures would finally reorient itself to the maximum in-situ stress direction, thus increase chances of creating one simple transverse fracture along maximum in-situ stress orientation. Because the strong stress interference of competing fractures, the possible breakdown of casing and perforation tunnels should be considered before well completion. The simulation results from this study offer some insights to enhance fixed plane perforation design for hydraulic fracturing treatments.
{"title":"The Numerical Simulation of Hydraulic Fracture Propagation with Competing Perforations at the Defining Plane","authors":"Xian Shi, Dongjie Li, Yuanfang Cheng, Zhongying Han, W. Fu","doi":"10.2118/191887-MS","DOIUrl":"https://doi.org/10.2118/191887-MS","url":null,"abstract":"\u0000 Fixed plane perforation technology is regarded as a good mean to address near wellbore tortuosity and reduce breakdown pressure in low permeability reservoirs. To better understand of the fracture behavior in wellbore perforations at the defining plane, a 2D finite element model has been implemented in ABAQUS to investigate the effects of mechanical, perforation and treatment parameters on hydraulic fracture propagation path. The global zero thickness cohesive elements have been inserted into numerical model, thus the existence of natural fractures on patterns of fracture propagation can be considered in this model. It shows that there is a great impact of natural fracture on the fracture propagation path. Moreover, the fracturing fluid viscosity, pumping rate, in-situ stress and perforation parameters also play critical roles on fracture propagation. Comparisons of numerical simulations show that the effects of the stress anisotropy, pumping rate, fluid viscosity, Young's modulus, Poisson's ratio and perforation intersection angle on the hydraulic fracture geometry of exterior fractures and interior fracture at the defining plane are different. It found that the width of interior fracture is almost zero at the near wellbore zone at the end of pumping which induced by the stress interference of neighboring fractures in some cases, thus perforations design at the defining plane must be carefully considered. Additionally, in most cases, hydraulic fractures from exterior perforations tend to propagate upward and downward simultaneously. Although hydraulic fractures initiated from a perforation that misaligned with the direction along the maximum in-situ stress initially at short distance, hydraulic fractures would finally reorient itself to the maximum in-situ stress direction, thus increase chances of creating one simple transverse fracture along maximum in-situ stress orientation. Because the strong stress interference of competing fractures, the possible breakdown of casing and perforation tunnels should be considered before well completion. The simulation results from this study offer some insights to enhance fixed plane perforation design for hydraulic fracturing treatments.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89514267","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}
Theerapat Suppachokniun, Marut Wantawin, T. Kiatrabile
After decades of conventional oil production from multi-layered reservoirs of Phisanulok basin in Thailand, the streamlined implementation of hydraulic fracturing following the successful pilot has recently made production from tight resources economically viable. This paper presents the strategic expansion of hydraulic fracturing activities that has evolved to full field implementation for the first time in Thailand. The adopted practices and improved oil production associated with the project ultimately delivers sustainable development of tight oil reservoirs. The pilot fracturing campaign implemented after years of subsurface and geomechanics studies have been evaluated. The attractive outcome indicates the oil gain almost eight times the Estimated Ultimate Recovery according to decline curve analysis, leading to the asset scheme strategically developed for unlocking tight oil potentials from multi-layered reservoirs by hydraulic fracturing applications. The development strategies including (1) the continual fracturing activities in the proven areas, (2) the implementation in new formations, and (3) the revival of the existing non-productive wells are comprehensively discussed, followed by the fundamental considerations for design and implementation of hydraulic fracturing along the actual process. As a result, hydraulic fracturing have becomes the key technique serving tight sand development scheme and will be continuously implemented in larger scale to facilitate the target oil production, making the project a dynamic operation. Prudent subsurface management model and deliberate project planning and execution are inevitable. Oil gain was estimated from tight reservoirs mainly in the area where technology has been proven, and from the unproven areas and formations. Available geomechanical model in the proven area has been revisited, and updated to enhance the engineering design of fractures. Additional data acquisition approaches, including acoustic logs, have been proposed to obtain more understanding in unfamiliar areas and formations. Asset drilling schedule and hydraulic fracturing plan have been optimally arranged in a way that the dedicated wells maximize overall asset production. Essentially, the selection of candidate wells becomes the critical part of the project. Many existing wells encountered tight formation, but they are no longer economically viable due to rapid production decline. Based on geological evidences, production data, and well integrity status, the selected candidates were strategically included in the project scope, which also supports idle well restoration program. Key elements of the hydraulic fracturing project in Thailand from the success of pilot campaign to the first-ever full-scale implementation in effectively and sustainably developing tight, multi-layered reservoirs of Phitsanulok basin are captured. Subsurface management scheme; operation plan and execution; fracture design and treatment technique opt
{"title":"Maximising the Opportunity in Multi-Layered Tight Sand Reservoirs in a Mature Field by Hydraulic Fracturing: A Case Study of Tight Sand Development Project in Thailand","authors":"Theerapat Suppachokniun, Marut Wantawin, T. Kiatrabile","doi":"10.2118/192047-MS","DOIUrl":"https://doi.org/10.2118/192047-MS","url":null,"abstract":"\u0000 After decades of conventional oil production from multi-layered reservoirs of Phisanulok basin in Thailand, the streamlined implementation of hydraulic fracturing following the successful pilot has recently made production from tight resources economically viable. This paper presents the strategic expansion of hydraulic fracturing activities that has evolved to full field implementation for the first time in Thailand. The adopted practices and improved oil production associated with the project ultimately delivers sustainable development of tight oil reservoirs.\u0000 The pilot fracturing campaign implemented after years of subsurface and geomechanics studies have been evaluated. The attractive outcome indicates the oil gain almost eight times the Estimated Ultimate Recovery according to decline curve analysis, leading to the asset scheme strategically developed for unlocking tight oil potentials from multi-layered reservoirs by hydraulic fracturing applications. The development strategies including (1) the continual fracturing activities in the proven areas, (2) the implementation in new formations, and (3) the revival of the existing non-productive wells are comprehensively discussed, followed by the fundamental considerations for design and implementation of hydraulic fracturing along the actual process.\u0000 As a result, hydraulic fracturing have becomes the key technique serving tight sand development scheme and will be continuously implemented in larger scale to facilitate the target oil production, making the project a dynamic operation. Prudent subsurface management model and deliberate project planning and execution are inevitable. Oil gain was estimated from tight reservoirs mainly in the area where technology has been proven, and from the unproven areas and formations. Available geomechanical model in the proven area has been revisited, and updated to enhance the engineering design of fractures. Additional data acquisition approaches, including acoustic logs, have been proposed to obtain more understanding in unfamiliar areas and formations. Asset drilling schedule and hydraulic fracturing plan have been optimally arranged in a way that the dedicated wells maximize overall asset production. Essentially, the selection of candidate wells becomes the critical part of the project. Many existing wells encountered tight formation, but they are no longer economically viable due to rapid production decline. Based on geological evidences, production data, and well integrity status, the selected candidates were strategically included in the project scope, which also supports idle well restoration program.\u0000 Key elements of the hydraulic fracturing project in Thailand from the success of pilot campaign to the first-ever full-scale implementation in effectively and sustainably developing tight, multi-layered reservoirs of Phitsanulok basin are captured. Subsurface management scheme; operation plan and execution; fracture design and treatment technique opt","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89074375","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}
H. Alkinani, A. T. Al-Hameedi, S. Dunn-Norman, R. Flori, Steven Hilgedick, A. Amer, M. Alsaba
It is recognized that there is no single solution to lost circulation, and most treatment and trial-and-error. However, the screening guide presents a high-level ‘go to’ document with coherent guidelines, which engineers can utilize in making decisions regarding lost circulation treatments in major oil fields. The aim of this work is to describe how mud engineers can use the decision tree analysis (DTA) to evaluate and select the best treatments path for mitigating mud losses. Lost circulation events of Southern Iraq oil fields were statistically analyzed to determine treatment effectiveness. Also, the cost of each treatment, as well as the NPT that is associated with the treatment, is considered in this study. Data from over 1000 wells were gathered from various sources and reports; the treatments were classified by scenario -partial, severe, and complete losses - as well as cost, efficiency, and formation types. This paper is developed based on probabilities, expected monetary value (EMV), and decision tree analysis (DTA) to recommend the best-lost circulation treatments path for each type of losses. Traditionally, lost circulation in Southern Iraq area has been treated in a multitude of ways without consistent methodology. This analysis identifies and ranks the most effective treatments to create a "best" method/product recommendation and a flowchart suggesting additional measures in treating losses to optimize success and reduce overall cost and NPT. This paper presents the best treatment for each scenario - partial loss, severe losses and complete losses - both for product selection and engineering. This paper utilizes probability and economics in the decision-making process. This is the first study that considers a detailed probability and cost to treat the lost circulation problem. Thousands of treatment scenarios for each type of losses are conducted, and the EMVs for all scenarios are calculated. For each type of losses, the lowest EMV treatment strategy- that is practically applicable in the field and makes sense- is selected to be used to treat each type of losses to minimize NPT and cost. If the losses didn't stop after utilizing the proposed treatment strategies, it is recommended to use liner hanger to isolate the losses zone and then continue drilling. One challenge in drilling wells in Southern Iraq oil fields is the inconsistency of approaches to the lost circulation problem. Therefore, the result of this data analysis provides a path forward for Southern Iraq area lost circulation events and suggests probable methods that can be used in similar formations globally. Additionally, the methodology can be adapted to studying other types of formations and drilling challenges have the same geological properties in any major oil field.
{"title":"Economic Evaluation and Uncertainty Assessment of Lost Circulation Treatments and Materials in the Hartha Formation, Southern Iraq","authors":"H. Alkinani, A. T. Al-Hameedi, S. Dunn-Norman, R. Flori, Steven Hilgedick, A. Amer, M. Alsaba","doi":"10.2118/192097-ms","DOIUrl":"https://doi.org/10.2118/192097-ms","url":null,"abstract":"\u0000 It is recognized that there is no single solution to lost circulation, and most treatment and trial-and-error. However, the screening guide presents a high-level ‘go to’ document with coherent guidelines, which engineers can utilize in making decisions regarding lost circulation treatments in major oil fields. The aim of this work is to describe how mud engineers can use the decision tree analysis (DTA) to evaluate and select the best treatments path for mitigating mud losses.\u0000 Lost circulation events of Southern Iraq oil fields were statistically analyzed to determine treatment effectiveness. Also, the cost of each treatment, as well as the NPT that is associated with the treatment, is considered in this study. Data from over 1000 wells were gathered from various sources and reports; the\u0000 treatments were classified by scenario -partial, severe, and complete losses - as well as cost, efficiency, and formation types. This paper is developed based on probabilities, expected monetary value (EMV), and decision tree analysis (DTA) to recommend the best-lost circulation treatments path for each type of losses.\u0000 Traditionally, lost circulation in Southern Iraq area has been treated in a multitude of ways without consistent methodology. This analysis identifies and ranks the most effective treatments to create a \"best\" method/product recommendation and a flowchart suggesting additional measures in treating losses to optimize success and reduce overall cost and NPT. This paper presents the best treatment for each scenario - partial loss, severe losses and complete losses - both for product selection and engineering.\u0000 This paper utilizes probability and economics in the decision-making process. This is the first study that considers a detailed probability and cost to treat the lost circulation problem. Thousands of treatment scenarios for each type of losses are conducted, and the EMVs for all scenarios are calculated. For each type of losses, the lowest EMV treatment strategy- that is practically applicable in the field and makes sense- is selected to be used to treat each type of losses to minimize NPT and cost. If the losses didn't stop after utilizing the proposed treatment strategies, it is recommended to use liner hanger to isolate the losses zone and then continue drilling.\u0000 One challenge in drilling wells in Southern Iraq oil fields is the inconsistency of approaches to the lost circulation problem. Therefore, the result of this data analysis provides a path forward for Southern Iraq area lost circulation events and suggests probable methods that can be used in similar formations globally. Additionally, the methodology can be adapted to studying other types of formations and drilling challenges have the same geological properties in any major oil field.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90356089","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}
Cationic surfactants have been proven to be highly effective in improving oil recovery in carbonate reservoirs with low surfactant loss due to adsorption. However, toxicity concerns and the cost of formulation have impeded their widespread usage in the oil and gas industry. Our study focuses on developing an economic and environmentally friendly solution to this challenge. Soybean oil was used as the raw material to synthesize a surfactant that had 3 cationic sites. The resulting formulation, in conjunction with an ethanol co-solvent, was tested for emulsion and rock-fluid behavior with dolomitic reservoir rocks and oil sampled from a producing well in Morrow County, Ohio. Interfacial tension (IFT) and contact angle measurements were conducted to characterize rock-fluid behavior of the surfactant. Estrogenic and anti-estrogenic activity were evaluated to help understand its environmental impact. Finally, oil recovery was measured using spontaneous imbibition tests and the results were compared to those obtained using cationic and anionic surfactants supplied by a commercial vendor. All the tests were conducted at standard atmospheric conditions except the imbibition studies, which were conducted at reservoir temperature. Our soy-based surfactant reduced the IFT by 60% and changed wettability from oil-wet to water-wet at concentrations lower than 3 gpt. No estrogenic or anti-estrogenic activity was detected for the surfactant at very high testing concentrations. The soy-based surfactant outperformed both the commercial anionic and cationic surfactants in imbibition tests recovering 35% of the oil originally in place (OOIP) inside the rock while the commercial cationic and anionic surfactants recovered 27% and 18% of OOIP, respectively. These encouraging results suggest that our soy-based surfactant has the potential to provide cheap and eco-friendly solutions for improving oil recovery from tight carbonate reservoirs in addition to other potential near-wellbore performance enhancements that are currently being investigated. We believe this novel additive has the potential to solve oil recovery and near-wellbore issues at a lower cost to the operator and lesser impact on the environment compared to the products in use today.
{"title":"Novel Eco-Friendly Cationic Surfactant for Improving Oil Recovery from Carbonate Reservoirs","authors":"M. Valluri, Rob Cain, R. Lalgudi","doi":"10.2118/191947-MS","DOIUrl":"https://doi.org/10.2118/191947-MS","url":null,"abstract":"\u0000 Cationic surfactants have been proven to be highly effective in improving oil recovery in carbonate reservoirs with low surfactant loss due to adsorption. However, toxicity concerns and the cost of formulation have impeded their widespread usage in the oil and gas industry. Our study focuses on developing an economic and environmentally friendly solution to this challenge.\u0000 Soybean oil was used as the raw material to synthesize a surfactant that had 3 cationic sites. The resulting formulation, in conjunction with an ethanol co-solvent, was tested for emulsion and rock-fluid behavior with dolomitic reservoir rocks and oil sampled from a producing well in Morrow County, Ohio. Interfacial tension (IFT) and contact angle measurements were conducted to characterize rock-fluid behavior of the surfactant. Estrogenic and anti-estrogenic activity were evaluated to help understand its environmental impact. Finally, oil recovery was measured using spontaneous imbibition tests and the results were compared to those obtained using cationic and anionic surfactants supplied by a commercial vendor. All the tests were conducted at standard atmospheric conditions except the imbibition studies, which were conducted at reservoir temperature.\u0000 Our soy-based surfactant reduced the IFT by 60% and changed wettability from oil-wet to water-wet at concentrations lower than 3 gpt. No estrogenic or anti-estrogenic activity was detected for the surfactant at very high testing concentrations. The soy-based surfactant outperformed both the commercial anionic and cationic surfactants in imbibition tests recovering 35% of the oil originally in place (OOIP) inside the rock while the commercial cationic and anionic surfactants recovered 27% and 18% of OOIP, respectively.\u0000 These encouraging results suggest that our soy-based surfactant has the potential to provide cheap and eco-friendly solutions for improving oil recovery from tight carbonate reservoirs in addition to other potential near-wellbore performance enhancements that are currently being investigated. We believe this novel additive has the potential to solve oil recovery and near-wellbore issues at a lower cost to the operator and lesser impact on the environment compared to the products in use today.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75991778","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
P. Cadogan, K. Seth, Richard Crabtree, V. Beales, A. Alsayed, B. Cheong
As subsea completion and tie-back development plans become more plentiful, the impact of sand failure on production often severely impacts the economics of a gas field. The integrity of downhole, subsea and facility equipment may be compromised due to excessive sand production which can potentially lead to catastrophic failure. In cased and perforated sand-face completions, good cement sheath coverage across the casing can act as the main defense against excessive sand production. An integrated approach involving cement design, execution and subsequent evaluation is therefore critical to minimise sand production during the life of the well. In this paper, we outline the evolution of the process of cement design, placement and evaluation used in a multi-well development campaign by an operator to achieve quality cement placement across the entire well length of the sub-horizontal wells. At the commencement of the drilling campaign, perforation intervals were initially limited due to the combination of high levels of sanding risk and interpreted cement log. To limit unperforated sections, a dual pronged approach was instigated looking at both cement design and operations, and cement bond log evaluation. As the campaign progressed, both elements were improved leading to an overall improvement with respect to perforation length. Challenges overcome included lost circulation in fractured formation, poor mud removal in extended horizontal casing, gas migration into the cement sheath, the presence of micro annuli by the loss of acoustic coupling due to oil-wet casing and test pressure applied between cementing operations and evaluation. In this paper, the entire cementing program design, placement and evaluation workflow will be explained with specific examples from the field development. Special focus will be given to the evaluation of the cement using state-of-the-art high-resolution wireline technology leading to a reduction in interpretation uncertainty through advanced workflows. Finally, examples will be provided where the inputs from the logs were integrated with both drilling and petrophysical data to evaluate the sanding propensity, thus allowing the operator to confidently perforate high-risk zones and ultimately improving well productivity.
{"title":"An Integrated Cement Design and Evaluation to Reduce Downhole Sanding Risk","authors":"P. Cadogan, K. Seth, Richard Crabtree, V. Beales, A. Alsayed, B. Cheong","doi":"10.2118/192022-MS","DOIUrl":"https://doi.org/10.2118/192022-MS","url":null,"abstract":"\u0000 As subsea completion and tie-back development plans become more plentiful, the impact of sand failure on production often severely impacts the economics of a gas field. The integrity of downhole, subsea and facility equipment may be compromised due to excessive sand production which can potentially lead to catastrophic failure. In cased and perforated sand-face completions, good cement sheath coverage across the casing can act as the main defense against excessive sand production. An integrated approach involving cement design, execution and subsequent evaluation is therefore critical to minimise sand production during the life of the well.\u0000 In this paper, we outline the evolution of the process of cement design, placement and evaluation used in a multi-well development campaign by an operator to achieve quality cement placement across the entire well length of the sub-horizontal wells.\u0000 At the commencement of the drilling campaign, perforation intervals were initially limited due to the combination of high levels of sanding risk and interpreted cement log. To limit unperforated sections, a dual pronged approach was instigated looking at both cement design and operations, and cement bond log evaluation. As the campaign progressed, both elements were improved leading to an overall improvement with respect to perforation length. Challenges overcome included lost circulation in fractured formation, poor mud removal in extended horizontal casing, gas migration into the cement sheath, the presence of micro annuli by the loss of acoustic coupling due to oil-wet casing and test pressure applied between cementing operations and evaluation.\u0000 In this paper, the entire cementing program design, placement and evaluation workflow will be explained with specific examples from the field development. Special focus will be given to the evaluation of the cement using state-of-the-art high-resolution wireline technology leading to a reduction in interpretation uncertainty through advanced workflows. Finally, examples will be provided where the inputs from the logs were integrated with both drilling and petrophysical data to evaluate the sanding propensity, thus allowing the operator to confidently perforate high-risk zones and ultimately improving well productivity.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78154872","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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