A. Ataei, E. Motaei, Mohammad Ebrahim Yazdi, R. Masoudi, Aamir Bashir
Rate Transient Analysis (RTA) has been used in gas reservoirs as a proven method for reserve estimation, well diagnostic and production performance evaluations. The authors have demonstrated several case studies showing the application of production analysis (PA) for reservoir characterization in gas and single phase oil reservoirs previously (Motaei, 2017, Ghanei and Ataei 2017, Ataei 2018). The adopted method for Integrated Production Analysis (IPA) works well in those case studies after combining the available data from RTA, PTA, or Material balance and basic reservoir engineering tools. The RTA found to be completing those is based on simple production data analysis using flowing data rather than limited shut in and less accurate ones. With benefit of continuous monitoring of FBHP using PDG, it is possible to evaluate the interferences and boundary in distance beside conventional reservoir properties like permeability and skin. These methods were found to be extremely powerful and popular particularly with the high resolution data from pressure downhole gauges (PDG). In this paper we have analyzed the available production data from a gas reservoir in offshore environment in South East Asia. It has been developed with five high PI wells and smart completion and monitored closely with PDG and other surveillance data to understand the contact movement during the production history. Due to the complexity of the field, different methods of production data analysis were used to understand the production performances. The recent advances in RTA allows us to apply the classical single well analysis method to a multiple well and multiple phase flow using Generalized Pseudo Pressure (GPP). The previously published workflow by the authors (Ghanei and Ataei, 2017) is used for this case study. We evaluate this technique for a multi well gas field with advancing aquifer. The connected volumes as estimated by single well analysis will be used for a group of wells which are communicating and have interference. We have also used a simple reservoir modelling approach to define scenarios which fit the production data and can be used for forecasting which can potentially save study teams time when deciding on the potential value and defining the targets of a major infill drilling project.
{"title":"Rate Transient Analysis RTA and Its Application for Well Connectivity Analysis: An Integrated Production Driven Reservoir Characterization and a Case Study","authors":"A. Ataei, E. Motaei, Mohammad Ebrahim Yazdi, R. Masoudi, Aamir Bashir","doi":"10.2118/192046-MS","DOIUrl":"https://doi.org/10.2118/192046-MS","url":null,"abstract":"\u0000 Rate Transient Analysis (RTA) has been used in gas reservoirs as a proven method for reserve estimation, well diagnostic and production performance evaluations. The authors have demonstrated several case studies showing the application of production analysis (PA) for reservoir characterization in gas and single phase oil reservoirs previously (Motaei, 2017, Ghanei and Ataei 2017, Ataei 2018). The adopted method for Integrated Production Analysis (IPA) works well in those case studies after combining the available data from RTA, PTA, or Material balance and basic reservoir engineering tools. The RTA found to be completing those is based on simple production data analysis using flowing data rather than limited shut in and less accurate ones. With benefit of continuous monitoring of FBHP using PDG, it is possible to evaluate the interferences and boundary in distance beside conventional reservoir properties like permeability and skin.\u0000 These methods were found to be extremely powerful and popular particularly with the high resolution data from pressure downhole gauges (PDG).\u0000 In this paper we have analyzed the available production data from a gas reservoir in offshore environment in South East Asia. It has been developed with five high PI wells and smart completion and monitored closely with PDG and other surveillance data to understand the contact movement during the production history. Due to the complexity of the field, different methods of production data analysis were used to understand the production performances. The recent advances in RTA allows us to apply the classical single well analysis method to a multiple well and multiple phase flow using Generalized Pseudo Pressure (GPP).\u0000 The previously published workflow by the authors (Ghanei and Ataei, 2017) is used for this case study. We evaluate this technique for a multi well gas field with advancing aquifer. The connected volumes as estimated by single well analysis will be used for a group of wells which are communicating and have interference. We have also used a simple reservoir modelling approach to define scenarios which fit the production data and can be used for forecasting which can potentially save study teams time when deciding on the potential value and defining the targets of a major infill drilling project.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"118 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88063710","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}
D. K. Agrawal, Ke Xu, Qusai A. Darugar, V. Khabashesku
Nanoparticle (NP) based enhanced oil recovery (Nano-EOR) has been considered as a promising future EOR strategy. However, although many mechanisms of Nano-EOR have been proposed, a lack of direct connections between the pore-scale mechanisms and the macro-scale oil recovery performance makes it hard to determine which mechanisms are dominant. In this work, we discovered a novel phenomenon of nanoparticle-crude oil interaction in pore-scale. Multi-scale experiments were conducted to connect this novel pore-scale phenomenon's role to oil recovery performance. A microchannel with dead-end pore was used to observe crude oil-NP interactions, on which crude oil can be trapped in the dead-end pore with a stable crude oil-aqueous phase interface at the pore-throat. A glass porous micromodel was used to conduct oil displacement experiments. ASW was used as the secondary flooding fluid, and 2000 PPM negatively charged NP in ASW was applied as the tertiary flooding fluid. Saturation profiles were recorded and analyzed by advanced image analysis tools. A coreflood through the sandstone sample was also conducted with similar conditions to the micromodel-flood experiments. A phenomenon that has never been reported was observed from the dead-end pore microchannel. It was observed that crude oil can considerably swell when contacting the nanoparticle aqueous suspension. In an ideal case (5 wt% NP in DI water), the oil volume more than doubled after a 50-hour swelling. The possible explanation for the crude oil swelling could be spontaneous formation of water droplets in the crude oil phase. NP can very likely affect the distribution of natural surfactants in crude oil (on the interface or inside oil phase), which breaks the water balance between aqueous phase and crude oil. This view has received support from quantitative experiments. It was shown from 2.5 D micromodel flood experiments that 11.8% incremental oil recovery comes slowly and continuously in more than 20 hours (40 pore volumes). From a saturation profile analysis, swelling of crude oil was found to improve sweep efficiency. Coreflood experiments also showed that the incremental oil was slowly and continuously recovered in about 20 hours during NP flooding. We propose that reduction of local water mobility by oil swelling in the swept region is the mechanism of sweep efficiency improvement. Swelling of crude oil under a NP environment was observed for the first time, with a systematic theory proposed and examined by quantitative experiments. The micromodel flood and coreflood experiments showed slow incremental oil recovery with a similar time scale to the oil swelling. Image analysis on the micromodel flood demonstrated improvement in the sweep efficiency during NP flooding. The mechanism for this sweep improvement is proposed.
{"title":"Enhanced Oil Recovery by Nanoparticle-Induced Crude Oil Swelling: Pore-Scale Experiments and Understanding","authors":"D. K. Agrawal, Ke Xu, Qusai A. Darugar, V. Khabashesku","doi":"10.2118/191971-MS","DOIUrl":"https://doi.org/10.2118/191971-MS","url":null,"abstract":"\u0000 Nanoparticle (NP) based enhanced oil recovery (Nano-EOR) has been considered as a promising future EOR strategy. However, although many mechanisms of Nano-EOR have been proposed, a lack of direct connections between the pore-scale mechanisms and the macro-scale oil recovery performance makes it hard to determine which mechanisms are dominant. In this work, we discovered a novel phenomenon of nanoparticle-crude oil interaction in pore-scale. Multi-scale experiments were conducted to connect this novel pore-scale phenomenon's role to oil recovery performance.\u0000 A microchannel with dead-end pore was used to observe crude oil-NP interactions, on which crude oil can be trapped in the dead-end pore with a stable crude oil-aqueous phase interface at the pore-throat. A glass porous micromodel was used to conduct oil displacement experiments. ASW was used as the secondary flooding fluid, and 2000 PPM negatively charged NP in ASW was applied as the tertiary flooding fluid. Saturation profiles were recorded and analyzed by advanced image analysis tools. A coreflood through the sandstone sample was also conducted with similar conditions to the micromodel-flood experiments.\u0000 A phenomenon that has never been reported was observed from the dead-end pore microchannel. It was observed that crude oil can considerably swell when contacting the nanoparticle aqueous suspension. In an ideal case (5 wt% NP in DI water), the oil volume more than doubled after a 50-hour swelling. The possible explanation for the crude oil swelling could be spontaneous formation of water droplets in the crude oil phase. NP can very likely affect the distribution of natural surfactants in crude oil (on the interface or inside oil phase), which breaks the water balance between aqueous phase and crude oil. This view has received support from quantitative experiments. It was shown from 2.5 D micromodel flood experiments that 11.8% incremental oil recovery comes slowly and continuously in more than 20 hours (40 pore volumes). From a saturation profile analysis, swelling of crude oil was found to improve sweep efficiency. Coreflood experiments also showed that the incremental oil was slowly and continuously recovered in about 20 hours during NP flooding. We propose that reduction of local water mobility by oil swelling in the swept region is the mechanism of sweep efficiency improvement.\u0000 Swelling of crude oil under a NP environment was observed for the first time, with a systematic theory proposed and examined by quantitative experiments. The micromodel flood and coreflood experiments showed slow incremental oil recovery with a similar time scale to the oil swelling. Image analysis on the micromodel flood demonstrated improvement in the sweep efficiency during NP flooding. The mechanism for this sweep improvement is proposed.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"68 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88111385","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}
Outcomes for oil and gas projects often fall short of the expectations predicted at project sanction. Appropriate use of Front End Loading (FEL) and Decision Analysis (DA) to achieve high Decision Quality (DQ) should increase the likelihood of achieving better outcomes. However, despite being successful methodologies, research has shown that they are not always applied. The focus of this paper is on how to encourage people to make better use of FEL and DA. Previous results from this research program have shown two key reasons why FEL and DA are not used more: an over-reliance on ‘experience’ and judgment for decision-making, rather than the use of structured processes; and projects being ‘schedule-driven’, i.e. meeting target dates being the primary objective. This paper focuses on insights from a survey conducted both to answer questions raised by this previous research and test the likely uptake of methods designed to encourage more effective use of FEL and DA/DQ. It shows that there is strong agreement that good FEL leads to better project outcomes, and that the FEL benchmark score is a good indicator of readiness for project sanction. However, perhaps competing with the desire to complete FEL, is the view (of around 2/3 of respondents) that it is important to drive the schedule in order to prevent ‘overworking’ – continued activity that adds little value. All respondents agreed that it is essential: that the decision maker clarifies the frame, scope and criteria for the decision; and to have regular discussions between the decision maker and the project team to bring alignment. However, responses indicated that these only occur in practice around half of the time. Similarly, formal assessments of DQ are made in less than half of key project decisions. Several novel solutions are proposed for increasing the likelihood of better project outcomes by improving the uptake and use of FEL and DA/DQ. These include: just-in-time training on FEL and DA/DQ; basing performance incentives on achieving high DQ and good FEL; and, developing a simple pragmatic assessment of FEL that can be used in-house. These suggestions were all supported by a majority of survey respondents.
{"title":"Improving Outcomes for Oil and Gas Projects Through Better Use of Front End Loading and Decision Analysis","authors":"David Newman, S. Begg, Matthew Welsh","doi":"10.2118/192129-MS","DOIUrl":"https://doi.org/10.2118/192129-MS","url":null,"abstract":"\u0000 Outcomes for oil and gas projects often fall short of the expectations predicted at project sanction. Appropriate use of Front End Loading (FEL) and Decision Analysis (DA) to achieve high Decision Quality (DQ) should increase the likelihood of achieving better outcomes. However, despite being successful methodologies, research has shown that they are not always applied. The focus of this paper is on how to encourage people to make better use of FEL and DA.\u0000 Previous results from this research program have shown two key reasons why FEL and DA are not used more: an over-reliance on ‘experience’ and judgment for decision-making, rather than the use of structured processes; and projects being ‘schedule-driven’, i.e. meeting target dates being the primary objective. This paper focuses on insights from a survey conducted both to answer questions raised by this previous research and test the likely uptake of methods designed to encourage more effective use of FEL and DA/DQ. It shows that there is strong agreement that good FEL leads to better project outcomes, and that the FEL benchmark score is a good indicator of readiness for project sanction. However, perhaps competing with the desire to complete FEL, is the view (of around 2/3 of respondents) that it is important to drive the schedule in order to prevent ‘overworking’ – continued activity that adds little value. All respondents agreed that it is essential: that the decision maker clarifies the frame, scope and criteria for the decision; and to have regular discussions between the decision maker and the project team to bring alignment. However, responses indicated that these only occur in practice around half of the time. Similarly, formal assessments of DQ are made in less than half of key project decisions.\u0000 Several novel solutions are proposed for increasing the likelihood of better project outcomes by improving the uptake and use of FEL and DA/DQ. These include: just-in-time training on FEL and DA/DQ; basing performance incentives on achieving high DQ and good FEL; and, developing a simple pragmatic assessment of FEL that can be used in-house. These suggestions were all supported by a majority of survey respondents.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86954471","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. Alam, S. Pooniwala, Malvika Nagarkoti, Waqas Zafar Cheema, Mohammad Al-Othman, E. Anthony
Water dump flood is a non-conventional and cheaper alternative as compared to surface water injection commonly used to support reservoir pressure. The major costs associated with surface injection includes water treatment as well as sourcing of the water. The dump flood technique helps eliminate these costs thereby improving project and field economics. A dump flood technique eliminates the requirement of drilling an additional water producer well. In order for the dump flood technique to be successful, adequate production from the source and good injection rates into the target interval are key requirements. If either one of them are not met there is likely to be detrimental effects on the objective of the dumpflood. This paper details the risks and challenges identified for the subject well and the methods & technologies implemented to ensure the success of the project. As part of the water injection strategy in the subject field, water dump flood was deployed. These wells source water from a prolific aquifer and with the aid of artificial lift, and the water was then injected into the upper reservoir to improve sweep efficiency and pressure maintenance. Dump flood technology uses two perforation intervals : one source interval and another as an injection interval. For the subject well, water productivity was established from the source formation. Upon initial tests, the target injection zone showed poor injectivity both pre- and post- matrix stimulation. Hence a new strategy of implementing hydraulic fracturing to improve the injectivity in conjunction with the dump flooding technique in the subject well was attempted for the first time in Kuwait. Special consideration had to be taken while optimizing hydraulic fracturing design taking into account pump discharge pressure and formation closure pressure. This paper also covers the special design considerations taken into account when selecting and designing the artificial lift equipment for a fractured and dump flooded well. Successful execution of hydraulic fracturing was critical in order to achieve the required injectivity in the target formation. During the execution of hydraulic fracturing, it was observed that once the near well bore damage was by-passed, the fluid leak-off increased significantly due to high formation permeability. This paper will detail the various decisions taken during operational execution to ensure success of the treatment. Post fracturing results that contributed to the success of the first hydraulically fractured dump flood well in the country will be discussed. This success ensured that the well could be completed with the designed completion and artificial lift strategy resulting in minimal workover requirement. The lessons learnt from this first hydraulic fractured dump flood well will be applied across the field. The technique will help to optimize recovery and project economics through efficient injection. This technique unlocks a new method which will p
{"title":"First Hydraulically Fractured Dump Flood Implementation in Kuwait: A Case Study","authors":"A. Alam, S. Pooniwala, Malvika Nagarkoti, Waqas Zafar Cheema, Mohammad Al-Othman, E. Anthony","doi":"10.2118/191882-MS","DOIUrl":"https://doi.org/10.2118/191882-MS","url":null,"abstract":"\u0000 Water dump flood is a non-conventional and cheaper alternative as compared to surface water injection commonly used to support reservoir pressure. The major costs associated with surface injection includes water treatment as well as sourcing of the water. The dump flood technique helps eliminate these costs thereby improving project and field economics. A dump flood technique eliminates the requirement of drilling an additional water producer well. In order for the dump flood technique to be successful, adequate production from the source and good injection rates into the target interval are key requirements. If either one of them are not met there is likely to be detrimental effects on the objective of the dumpflood. This paper details the risks and challenges identified for the subject well and the methods & technologies implemented to ensure the success of the project.\u0000 As part of the water injection strategy in the subject field, water dump flood was deployed. These wells source water from a prolific aquifer and with the aid of artificial lift, and the water was then injected into the upper reservoir to improve sweep efficiency and pressure maintenance. Dump flood technology uses two perforation intervals : one source interval and another as an injection interval. For the subject well, water productivity was established from the source formation. Upon initial tests, the target injection zone showed poor injectivity both pre- and post- matrix stimulation. Hence a new strategy of implementing hydraulic fracturing to improve the injectivity in conjunction with the dump flooding technique in the subject well was attempted for the first time in Kuwait. Special consideration had to be taken while optimizing hydraulic fracturing design taking into account pump discharge pressure and formation closure pressure. This paper also covers the special design considerations taken into account when selecting and designing the artificial lift equipment for a fractured and dump flooded well.\u0000 Successful execution of hydraulic fracturing was critical in order to achieve the required injectivity in the target formation. During the execution of hydraulic fracturing, it was observed that once the near well bore damage was by-passed, the fluid leak-off increased significantly due to high formation permeability. This paper will detail the various decisions taken during operational execution to ensure success of the treatment. Post fracturing results that contributed to the success of the first hydraulically fractured dump flood well in the country will be discussed. This success ensured that the well could be completed with the designed completion and artificial lift strategy resulting in minimal workover requirement.\u0000 The lessons learnt from this first hydraulic fractured dump flood well will be applied across the field. The technique will help to optimize recovery and project economics through efficient injection. This technique unlocks a new method which will p","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"89 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80858292","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}
Digital rocks obtained from high-resolution micro-computed tomography (micro-CT) imaging has quickly emerged as a powerful tool for studying pore-scale transport phenomena in petroleum engineering. In such frameworks, digital rock analysis usually carries the problematic aspect of segmenting greyscale images into different phases for quantifying many physical properties. Fine pore structures, such as small rock fissures, are usually lost during segmentation. In addition, user bias in this process can lead to significantly different results. An alternative approach based on deep learning is proposed. Convolutional Neural Networks (CNN) are utilized to rapidly predict several porous media properties from 2D greyscale micro-computed tomography images in a supervised learning frame. A dataset of greyscale micro-CT images of three different sandstones species is prepared for this study. The image dataset is segmented, and pore networks are extracted to compute porosity, coordination number, and average pore size for training and validating our model predictions. The greyscale images (input) and the computed properties (output) are uploaded to a deep neural network for training and validation in an end-to-end regression scheme. Overall, our model estimates porosity, coordination number, and average pore size with an average error of 0.05, 0.17, and 1.8μm, respectively. Training wall-time and prediction error analysis are also discussed. This is a first step to use artificial intelligence and machine learning methods for the robust prediction of porous media properties from unprocessed image-driven data.
{"title":"Deep Learning Convolutional Neural Networks to Predict Porous Media Properties","authors":"Naif Alqahtani, R. Armstrong, P. Mostaghimi","doi":"10.2118/191906-MS","DOIUrl":"https://doi.org/10.2118/191906-MS","url":null,"abstract":"\u0000 Digital rocks obtained from high-resolution micro-computed tomography (micro-CT) imaging has quickly emerged as a powerful tool for studying pore-scale transport phenomena in petroleum engineering. In such frameworks, digital rock analysis usually carries the problematic aspect of segmenting greyscale images into different phases for quantifying many physical properties. Fine pore structures, such as small rock fissures, are usually lost during segmentation. In addition, user bias in this process can lead to significantly different results. An alternative approach based on deep learning is proposed. Convolutional Neural Networks (CNN) are utilized to rapidly predict several porous media properties from 2D greyscale micro-computed tomography images in a supervised learning frame. A dataset of greyscale micro-CT images of three different sandstones species is prepared for this study. The image dataset is segmented, and pore networks are extracted to compute porosity, coordination number, and average pore size for training and validating our model predictions. The greyscale images (input) and the computed properties (output) are uploaded to a deep neural network for training and validation in an end-to-end regression scheme. Overall, our model estimates porosity, coordination number, and average pore size with an average error of 0.05, 0.17, and 1.8μm, respectively. Training wall-time and prediction error analysis are also discussed. This is a first step to use artificial intelligence and machine learning methods for the robust prediction of porous media properties from unprocessed image-driven data.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"63 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80092324","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The objective of this paper is to outline the issues that should be considered and provide guidance on the assessment of reserves and resources in a variety of scenarios where petroleum accumulations straddle licence boundaries. Petroleum accumulations straddling boundaries are common. Global estimates of the numbers of fields which straddle boundaries vary but run into hundreds or thousands with several countries/basins reported to have up to half of discovered fields straddling at least one boundary. It is widely recognised that development of oil and gas fields straddling boundaries can be optimised through unitisation. However, less attention has been paid to the assessment of reserves and resources in such situations and how the nature and status of unitisation, or lack thereof, impacts reserves and resources assessment using the Petroleum Resources Management System (PRMS). Even in ideal situations where unitisation has been agreed, the methods and objectives of unitisation and reserves assessment are quite different. Unitisation is typically: based on in-place volumes, considers a single deterministic interpretation, follows specified technical procedures, without consideration of economics and is done at a specified time during a field's life, and may be followed by subsequent redeterminations. Reserves are: remaining recoverable volumes, consider a range of outcomes, do not follow specific procedures, do consider economics and are typically assessed at regular intervals, often annually, throughout a field's life. The paper will examine a range of scenarios from those where unitisation has been agreed, through those where unitisation is mandated but not yet in place, to those where no unitisation is either in place or mandated. Several factors influence how such situations should be assessed. The status of the field and data on either side of the boundary will be considered including: have wells been drilled on one or both sides? Is production occurring on one or both sides? What consideration should reserves assessors give to scheduled redeterminations where agreements, formulas and outcomes are unknown. There are many cases where production has occurred on both sides and unitisation is required retroactively. Regulatory requirements regarding unitisation vary throughout the world. Where present, regulations often require unitisation to occur, but the practice lags behind the legislation. There are also situations where production has occurred on one or both sides in "rule of capture" scenarios without any requirement or plan for unitisation. Accumulations straddling international boundaries introduce additional factors that should be considered.
{"title":"Reserves Assessment in Petroleum Accumulations Straddling Boundaries: The Relationship Between Reserves & Resources and Unitisation","authors":"D. Peacock","doi":"10.2118/192144-MS","DOIUrl":"https://doi.org/10.2118/192144-MS","url":null,"abstract":"\u0000 The objective of this paper is to outline the issues that should be considered and provide guidance on the assessment of reserves and resources in a variety of scenarios where petroleum accumulations straddle licence boundaries.\u0000 Petroleum accumulations straddling boundaries are common. Global estimates of the numbers of fields which straddle boundaries vary but run into hundreds or thousands with several countries/basins reported to have up to half of discovered fields straddling at least one boundary.\u0000 It is widely recognised that development of oil and gas fields straddling boundaries can be optimised through unitisation. However, less attention has been paid to the assessment of reserves and resources in such situations and how the nature and status of unitisation, or lack thereof, impacts reserves and resources assessment using the Petroleum Resources Management System (PRMS). Even in ideal situations where unitisation has been agreed, the methods and objectives of unitisation and reserves assessment are quite different. Unitisation is typically: based on in-place volumes, considers a single deterministic interpretation, follows specified technical procedures, without consideration of economics and is done at a specified time during a field's life, and may be followed by subsequent redeterminations. Reserves are: remaining recoverable volumes, consider a range of outcomes, do not follow specific procedures, do consider economics and are typically assessed at regular intervals, often annually, throughout a field's life.\u0000 The paper will examine a range of scenarios from those where unitisation has been agreed, through those where unitisation is mandated but not yet in place, to those where no unitisation is either in place or mandated. Several factors influence how such situations should be assessed. The status of the field and data on either side of the boundary will be considered including: have wells been drilled on one or both sides? Is production occurring on one or both sides? What consideration should reserves assessors give to scheduled redeterminations where agreements, formulas and outcomes are unknown. There are many cases where production has occurred on both sides and unitisation is required retroactively. Regulatory requirements regarding unitisation vary throughout the world. Where present, regulations often require unitisation to occur, but the practice lags behind the legislation. There are also situations where production has occurred on one or both sides in \"rule of capture\" scenarios without any requirement or plan for unitisation. Accumulations straddling international boundaries introduce additional factors that should be considered.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89965298","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}
Derong Xu, B. Bai, Ziyu Meng, Qiong Zhou, Zhe Li, Yao Lu, Hairong Wu, J. Hou, Wanli Kang
The exploration and development of super-low permeability reservoirs have become a global focus in recent years. However, conventional flooding systems commonly face problems of high injection pressure and poor displacement efficiency in super-low permeability reservoirs. Thus, it is imperative to find new flooding agents that tackle such problems. In this study, a novel ultra-low interfacial tension (IFT) nanofluid was formulated, consisting of surfactants to achieve ultra-low IFT and silica nanoparticles to reduce injection pressure. The compatibility test between the surfactants and silica nanoparticles in 10,000 mg/L NaCl solution at 90 °C was conducted to ensure their adaption to harsh reservoir conditions. Also, the effects of silica nanoparticles on the IFT and emulsion stability of the surfactant solution as well as wettability of reservoir rock were evaluated to determine the optimum concentration of nanoparticles. Finally, oil displacement efficiency of the nanofluid was assessed and compared from respective nanofluid flooding, surfactant flooding and surfactant-free nanofluid flooding. The compatibility results showed that the ultra-low IFT surfactant solution with silica nanoparticles remained clear and stable at 90 °C for one month. The surfactant solution can effectively emulsify oil, and the stability of the oil emulsion could be further improved in the presence of silica nanoparticles. In addition, the solution could achieve lower IFT at both low and high temperature with the addition of 0.01% silica nanoparticles. The silica nanoparticles could effectively alter the wettability of the rock, making it become more water-wet with increasing silica nanoparticle concentration. The displacement experiments through 0.2–0.3 mD tight cores indicated that the enhanced oil recovery could reach 21.12%OOIP by the nanofluid flooding after water flooding, higher than that of surfactant flooding (18.84% OOIP), and much higher than that of surfactant-free nanofluid flooding (3.48% OOIP). Moreover, the injection pressure difference was able to decrease nearly 50% after nanofluid injection in comparison with the occurrence of an increase in pressure along the surfactant solution injection. Thus, the combined surfactant and nanoparticles behaved excellent synergistic effect. The newly formulated surfactant based silica nanofluids can efficiently enhance oil recovery in comparison with water flooding, and significantly lower the injection pressure compared with the surfactant flooding. This work lays the foundation for the application of ultralow IFT nanofluid flooding technology in super-low permeability reservoirs.
{"title":"A Novel Ultra-Low Interfacial Tension Nanofluid for Enhanced Oil Recovery in Super-Low Permeability Reservoirs","authors":"Derong Xu, B. Bai, Ziyu Meng, Qiong Zhou, Zhe Li, Yao Lu, Hairong Wu, J. Hou, Wanli Kang","doi":"10.2118/192113-MS","DOIUrl":"https://doi.org/10.2118/192113-MS","url":null,"abstract":"\u0000 The exploration and development of super-low permeability reservoirs have become a global focus in recent years. However, conventional flooding systems commonly face problems of high injection pressure and poor displacement efficiency in super-low permeability reservoirs. Thus, it is imperative to find new flooding agents that tackle such problems.\u0000 In this study, a novel ultra-low interfacial tension (IFT) nanofluid was formulated, consisting of surfactants to achieve ultra-low IFT and silica nanoparticles to reduce injection pressure. The compatibility test between the surfactants and silica nanoparticles in 10,000 mg/L NaCl solution at 90 °C was conducted to ensure their adaption to harsh reservoir conditions. Also, the effects of silica nanoparticles on the IFT and emulsion stability of the surfactant solution as well as wettability of reservoir rock were evaluated to determine the optimum concentration of nanoparticles. Finally, oil displacement efficiency of the nanofluid was assessed and compared from respective nanofluid flooding, surfactant flooding and surfactant-free nanofluid flooding.\u0000 The compatibility results showed that the ultra-low IFT surfactant solution with silica nanoparticles remained clear and stable at 90 °C for one month. The surfactant solution can effectively emulsify oil, and the stability of the oil emulsion could be further improved in the presence of silica nanoparticles. In addition, the solution could achieve lower IFT at both low and high temperature with the addition of 0.01% silica nanoparticles. The silica nanoparticles could effectively alter the wettability of the rock, making it become more water-wet with increasing silica nanoparticle concentration. The displacement experiments through 0.2–0.3 mD tight cores indicated that the enhanced oil recovery could reach 21.12%OOIP by the nanofluid flooding after water flooding, higher than that of surfactant flooding (18.84% OOIP), and much higher than that of surfactant-free nanofluid flooding (3.48% OOIP). Moreover, the injection pressure difference was able to decrease nearly 50% after nanofluid injection in comparison with the occurrence of an increase in pressure along the surfactant solution injection. Thus, the combined surfactant and nanoparticles behaved excellent synergistic effect.\u0000 The newly formulated surfactant based silica nanofluids can efficiently enhance oil recovery in comparison with water flooding, and significantly lower the injection pressure compared with the surfactant flooding. This work lays the foundation for the application of ultralow IFT nanofluid flooding technology in super-low permeability reservoirs.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"56 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85427424","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Chia, M. H. Yakup, M. Tamin, Nicholas Aloysius Surin, Khairul Akmal B Mazzlan, Muhammad Rinadi, A. Hassan
This paper details out the application of a predictive analysis tool to ‘S’ Field's commingled production, aiming to enhance production allocation and reservoir understanding without the need of well intervention and a reduced frequency of zonal rate tests and data acquisition. Allocation of the production data to its respective reservoirs is performed via a novel Multi-Phase Allocation method (MPA), taking into account the water production trending evolution derived from relative permeability behavior of oil-water in each reservoir to compute flow rates for liquid phases over time. The precision of the derived rates is constrained by actual zonal rates tests through Inflow Control Valves (ICVs). This method will be cross referenced against ‘S’ Field's existing zonal rate calculation algorithm, utilizing input data from well tests results and real time pressure and temperature data. The MPA method demonstrates improvement in the allocation of production data as compared to the conventional KH-methodology as MPA takes into account the water cut trending between reservoirs. Leveraging on ICVs to obtain actual zonal rate measurements, this greatly reduces the range of uncertainty in the allocation process. MPA derived production split ratios closely match the split ratios derived from the ‘S’ Field's existing zonal rate calculation algorithm, which utilizes input data from well tests results and real time pressure and temperature data from down hole gauges. It is observed that the usage of actual measured zonal rate tests reduces the range of uncertainty of the MPA data. A combination of novel multi-phase deliverability models coupled with smart field technologies such as intelligent completions and real-time surveillance and analysis tools will increase the accuracy of the back allocation of multi-phase production data in commingled reservoirs.
{"title":"Application of Novel Predictive Analytics for Data Allocation of Commingled Production in Smart Fields","authors":"M. Chia, M. H. Yakup, M. Tamin, Nicholas Aloysius Surin, Khairul Akmal B Mazzlan, Muhammad Rinadi, A. Hassan","doi":"10.2118/192078-MS","DOIUrl":"https://doi.org/10.2118/192078-MS","url":null,"abstract":"\u0000 This paper details out the application of a predictive analysis tool to ‘S’ Field's commingled production, aiming to enhance production allocation and reservoir understanding without the need of well intervention and a reduced frequency of zonal rate tests and data acquisition.\u0000 Allocation of the production data to its respective reservoirs is performed via a novel Multi-Phase Allocation method (MPA), taking into account the water production trending evolution derived from relative permeability behavior of oil-water in each reservoir to compute flow rates for liquid phases over time. The precision of the derived rates is constrained by actual zonal rates tests through Inflow Control Valves (ICVs). This method will be cross referenced against ‘S’ Field's existing zonal rate calculation algorithm, utilizing input data from well tests results and real time pressure and temperature data.\u0000 The MPA method demonstrates improvement in the allocation of production data as compared to the conventional KH-methodology as MPA takes into account the water cut trending between reservoirs. Leveraging on ICVs to obtain actual zonal rate measurements, this greatly reduces the range of uncertainty in the allocation process. MPA derived production split ratios closely match the split ratios derived from the ‘S’ Field's existing zonal rate calculation algorithm, which utilizes input data from well tests results and real time pressure and temperature data from down hole gauges.\u0000 It is observed that the usage of actual measured zonal rate tests reduces the range of uncertainty of the MPA data.\u0000 A combination of novel multi-phase deliverability models coupled with smart field technologies such as intelligent completions and real-time surveillance and analysis tools will increase the accuracy of the back allocation of multi-phase production data in commingled reservoirs.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75316101","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. Jiang, Liu Huifeng, Xiangtong Yang, Liu Yuan, Feng Jueyong, Ren Huining, Huo Guo
Keshen gas field is located in the southern foothill of Mount Tianshan, Western China. Administratively it belongs to Baicheng County, a poor and remote county. This county is composed of 20 ethnic groups, who have their own cultures and languages, which pose difficulties for project management. With a series of initiatives for cooperating with the local government and communities, a yearly natural gas productivity of 5 billion cubic meters were established within five years. A series of measures were taken to win the support of local government. A 108-kilometer long highway was constructed in the mountainous area and shared with local communities. A pipeline network was established to transmit natural gas from Keshen gas field to the suburban areas of Baicheng and other remote places, which changed the local main fuel from firewood into clean natural gas. We hired local people, trained them and gave them decent salaries. More than 2,000 job opportunities were provided to local ethnic minorities, which accounts for 18.5% of the total workers in this project. Thanks to the initiatives we have taken, a harmonious development mode was established in Keshen gas field. It was put into production within five year's construction. The average productivity of a single well is more than 500 thousand cubic meters. The total amount of taxes as well as the GDP of Baicheng County was twice as before. The southern Xinjiang pipeline network encircles half of the Tarim Basin. 41 towns along the pipeline and 4 million people are benefiting from the natural gas produced from Keshen gas field. In return, the local government and communities provided a lot of conveniences for the project crew. The government released several restrictions on seismic exploration and pipeline construction. Since the project crews were mostly from urban areas, the local residents also help us to recognize risks and formulate risk-reducing practices for conducting engineering work in the Gobi and desert area. We also instructed the local residents to do business with Keshen development project, including selling of construction and living materials, renting of equipment, transport vehicles, etc. This initiative also helped to reduce unemployment rate and benefit the project management as well. Keshen gas field is one of the most complicated reservoir in China, not only because of the ultra-deep HPHT reservoirs, but also because of the complicated social environment. A win-win cooperation mode between the Oilfield Company and local communities has been established after a series of initiatives. This set a solid foundation for the sustainable development of Keshen gas field and also set an example for the development of reservoirs in remote areas.
{"title":"Initiatives in Cooperating with Local Government and Communities Promote the Development of a HTHP Gas Field in Remote Area of China: Development of Keshen Gas Field","authors":"T. Jiang, Liu Huifeng, Xiangtong Yang, Liu Yuan, Feng Jueyong, Ren Huining, Huo Guo","doi":"10.2118/191955-MS","DOIUrl":"https://doi.org/10.2118/191955-MS","url":null,"abstract":"\u0000 Keshen gas field is located in the southern foothill of Mount Tianshan, Western China. Administratively it belongs to Baicheng County, a poor and remote county. This county is composed of 20 ethnic groups, who have their own cultures and languages, which pose difficulties for project management. With a series of initiatives for cooperating with the local government and communities, a yearly natural gas productivity of 5 billion cubic meters were established within five years.\u0000 A series of measures were taken to win the support of local government. A 108-kilometer long highway was constructed in the mountainous area and shared with local communities. A pipeline network was established to transmit natural gas from Keshen gas field to the suburban areas of Baicheng and other remote places, which changed the local main fuel from firewood into clean natural gas. We hired local people, trained them and gave them decent salaries. More than 2,000 job opportunities were provided to local ethnic minorities, which accounts for 18.5% of the total workers in this project.\u0000 Thanks to the initiatives we have taken, a harmonious development mode was established in Keshen gas field. It was put into production within five year's construction. The average productivity of a single well is more than 500 thousand cubic meters. The total amount of taxes as well as the GDP of Baicheng County was twice as before. The southern Xinjiang pipeline network encircles half of the Tarim Basin. 41 towns along the pipeline and 4 million people are benefiting from the natural gas produced from Keshen gas field. In return, the local government and communities provided a lot of conveniences for the project crew. The government released several restrictions on seismic exploration and pipeline construction. Since the project crews were mostly from urban areas, the local residents also help us to recognize risks and formulate risk-reducing practices for conducting engineering work in the Gobi and desert area. We also instructed the local residents to do business with Keshen development project, including selling of construction and living materials, renting of equipment, transport vehicles, etc. This initiative also helped to reduce unemployment rate and benefit the project management as well.\u0000 Keshen gas field is one of the most complicated reservoir in China, not only because of the ultra-deep HPHT reservoirs, but also because of the complicated social environment. A win-win cooperation mode between the Oilfield Company and local communities has been established after a series of initiatives. This set a solid foundation for the sustainable development of Keshen gas field and also set an example for the development of reservoirs in remote areas.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88213560","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}
Water is essential for energy exploitation, and moreover the contradiction between water resources and energy recovery seen in China is more severe than those in other countries. Given this, CO2 waterless fracturing, which improves the production and recovery factor of an individual well and meanwhile serves for water preservation and CO2 underground storage, can contribute to the sustainable development of China's oil industry. The continuity and reliability of equipment is a key technical aspect for the successful waterless fracturing, in which the operation is required to be done in a sealed, pressurized environment during the whole workflow, and the proppant-carrying capability of fluids is low. Therefore, strict requirements are raised up upon the equipment. On the basis of the dynamic fluid balance combined with the fluid phase evolution during the whole construction workflow and its effects on stimulation treatments, this paper optimized the design of key construction equipment, such as CO2 storage tanks, booster pumps, sealed blender trucks and fracturing pump trucks. Major improvements can be concluded as: 1) the vertical tank is used for the sealed blender, which enhances the control stability of sand supply process jointly by the pressure difference regulation and auger; 2) booster pump unit with high pump-rate capability are included in the system for liquid supply and fluid phase control; 3) the liquid supply combines the mobile transport tanks and fixed storage tanks to increase the liquid supply capability; 4) the fracturing system is equipped with eight special fracturing pumps for waterless fracturing, fulfilling the construction requirement of 20,000 hydraulic horse power. The whole equipment system has treatment capability of available pump rates up to 12 m3/min, sand volume of 27 m3 and CO2 injection of 1500 m3. In 2017, this equipment system was used in waterless fracturing for six times, with a maximum proppant input of 23 m3. Both the liquid and sand supply processes are found stable, and the production gain after stimulation is considerable. It is estimated that in tight reservoir, oil production brought by 1 unit volume of CO2 equals to that of 2.4 unit volume of water-based fracturing fluid. Providing that the average CO2 injection of waterless fracturing wells is 630 m3, a single well can save 1512 m3 water resource. This equipment system fully meets the requirement of fracturing in vertical and horizontal wells of unconventional resources, and can effectively support the further development of the waterless fracturing technology.
{"title":"Development and Application of Key Equipment of CO2 Waterless Fracturing","authors":"Lichen Zheng, S. Meng, Shi Chen, Qinghai Yang","doi":"10.2118/192069-MS","DOIUrl":"https://doi.org/10.2118/192069-MS","url":null,"abstract":"\u0000 Water is essential for energy exploitation, and moreover the contradiction between water resources and energy recovery seen in China is more severe than those in other countries. Given this, CO2 waterless fracturing, which improves the production and recovery factor of an individual well and meanwhile serves for water preservation and CO2 underground storage, can contribute to the sustainable development of China's oil industry.\u0000 The continuity and reliability of equipment is a key technical aspect for the successful waterless fracturing, in which the operation is required to be done in a sealed, pressurized environment during the whole workflow, and the proppant-carrying capability of fluids is low. Therefore, strict requirements are raised up upon the equipment. On the basis of the dynamic fluid balance combined with the fluid phase evolution during the whole construction workflow and its effects on stimulation treatments, this paper optimized the design of key construction equipment, such as CO2 storage tanks, booster pumps, sealed blender trucks and fracturing pump trucks.\u0000 Major improvements can be concluded as: 1) the vertical tank is used for the sealed blender, which enhances the control stability of sand supply process jointly by the pressure difference regulation and auger; 2) booster pump unit with high pump-rate capability are included in the system for liquid supply and fluid phase control; 3) the liquid supply combines the mobile transport tanks and fixed storage tanks to increase the liquid supply capability; 4) the fracturing system is equipped with eight special fracturing pumps for waterless fracturing, fulfilling the construction requirement of 20,000 hydraulic horse power. The whole equipment system has treatment capability of available pump rates up to 12 m3/min, sand volume of 27 m3 and CO2 injection of 1500 m3. In 2017, this equipment system was used in waterless fracturing for six times, with a maximum proppant input of 23 m3. Both the liquid and sand supply processes are found stable, and the production gain after stimulation is considerable.\u0000 It is estimated that in tight reservoir, oil production brought by 1 unit volume of CO2 equals to that of 2.4 unit volume of water-based fracturing fluid. Providing that the average CO2 injection of waterless fracturing wells is 630 m3, a single well can save 1512 m3 water resource. This equipment system fully meets the requirement of fracturing in vertical and horizontal wells of unconventional resources, and can effectively support the further development of the waterless fracturing technology.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"6 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":"88234375","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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