T. Olneva, D. Kuzmin, S. Rasskazova, A. Timirgalin
Big Data technologies are now being actively integrated into the oil and gas sector owing to the need to improve operational efficiency and to optimize a variety of processes. Successful projects in data processing automation have already been implemented, for example, new breakthroughs are expected in digital field modelling projects /1/. Geological and geophysical information accumulated over decades of studies in oil and gas bearing basins and fields development is a huge amount of data; Big Data approaches can be effectively applied to them, such as data mining, predictive analytics, training of a system on the reference objects. 3D seismic data is a classic example of Big Data. Their interpretation conventionally involves approaches based on Neural Networks, various classification and clustering algorithms /2/. According to the experts, the West Siberian Petroleum Basin being a holistic system, has unique properties such as existence of giant and unique hydrocarbon accumulations /3/. The potential of the basin has not yet been determined. The authors focused their attention on the Achimov play. Applying the Big Data approach to a regional database may allow establishing new patterns in fields distribution and will contribute to the development of new unique exploration criteria.
{"title":"Big Data Approach for Geological Study of the Big Region West Siberia","authors":"T. Olneva, D. Kuzmin, S. Rasskazova, A. Timirgalin","doi":"10.2118/191726-MS","DOIUrl":"https://doi.org/10.2118/191726-MS","url":null,"abstract":"\u0000 Big Data technologies are now being actively integrated into the oil and gas sector owing to the need to improve operational efficiency and to optimize a variety of processes. Successful projects in data processing automation have already been implemented, for example, new breakthroughs are expected in digital field modelling projects /1/.\u0000 Geological and geophysical information accumulated over decades of studies in oil and gas bearing basins and fields development is a huge amount of data; Big Data approaches can be effectively applied to them, such as data mining, predictive analytics, training of a system on the reference objects. 3D seismic data is a classic example of Big Data. Their interpretation conventionally involves approaches based on Neural Networks, various classification and clustering algorithms /2/.\u0000 According to the experts, the West Siberian Petroleum Basin being a holistic system, has unique properties such as existence of giant and unique hydrocarbon accumulations /3/. The potential of the basin has not yet been determined. The authors focused their attention on the Achimov play. Applying the Big Data approach to a regional database may allow establishing new patterns in fields distribution and will contribute to the development of new unique exploration criteria.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79515098","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 work is to assess the impact on productivity decline of altering the completion type in a deepwater Miocene reservoir. Typically to date, these types of assets have utilized Cased Hole FracPack (CHFP) completions as a basis of design. Wells in the Gulf of Mexico targeting the deepwater Miocene plays have seen significant Productivity Index (PI) decline within the first few years of production. Open Hole Gravel Pack (OHGP) and Open Hole FracPack (OHFP) completion types were selected as potential alternatives to CHFP. A coupled well, reservoir and geomechanical model was created to assess the impact of multiple potential damage components on matching the observed inflow performance from production logs. The model assesses probabilistically the weighting of each of six damage mechanisms (creep, fracture conductivity, fines migration, fracture connectivity, off-plane perforation contribution and drilling/completion fluid damage) on well performance. Based on this weighting, an assessment can then be made of their impact on the alternate completion types. Previous studies (Knobles et al. 2017) have indicated that cased hole completions are particularly susceptible to PI decline. Specifically, when unpropped perforation tunnels collapse, they reduce the inflow area into the wellbore and create a flow restriction. In higher permeability formations, the perforations not connected to the fracture (i.e. off-plane perforations) can contribute a significant portion of the well's production. It is important to note that if the connectivity and packing of the perforations is optimized and fracture is placed to within design specifications, little PI decline is observed. However, in the real world, this is not always the case. Three wells were used in this analysis. Two wells where decline was observed and a third well where no significant decline was observed. Results from the study indicated that if the two underperforming wells had utilized an OHGP completion, the PI degradation would have been mitigated. However, the upside production seen from the third well would not be attainable had the well been completed as an OHGP on an equivalent well trajectory. The results of the study also indicated that minimizing the drilling damage would be integral to the success of the OHGP completion in comparison to optimizing the completion placement in a CHFP. The paper addresses a significant issue of PI decline affecting deepwater wells and presents a potential remediation technique based on alternate completion types. The paper also presents a new methodology based on Design of Experiment to assess the contribution of various damage mechanism while incorporating the uncertainty around each based on available measurements.
这项工作的目的是评估改变完井类型对深水中新世储层产能下降的影响。到目前为止，这些类型的资产通常使用套管井FracPack (CHFP)完井作为设计的基础。墨西哥湾深水中新世油藏的油井在投产的头几年里，产能指数(PI)就出现了显著下降。裸眼砾石充填(OHGP)和裸眼FracPack (OHFP)完井类型被选为CHFP的潜在替代方案。建立了井、储层和地质力学耦合模型，以评估多种潜在损害因素对生产测井中观察到的流入动态的影响。该模型对六种损伤机制(蠕变、裂缝导流性、细粒运移、裂缝连通性、面外射孔贡献和钻/完井液损伤)对油井性能的影响进行概率加权评估。基于此权重，可以评估它们对替代完井类型的影响。之前的研究(Knobles et al. 2017)表明，套管井完井特别容易受到PI下降的影响。具体来说，当无支撑射孔隧道坍塌时，它们会减少流入井筒的面积，并产生流动限制。在高渗透率地层中，未与裂缝相连的射孔(即离面射孔)可以贡献很大一部分井的产量。需要注意的是，如果对射孔的连通性和充填进行了优化，并且将裂缝放置在设计规范范围内，则可以观察到很少的PI下降。然而，在现实世界中，情况并非总是如此。该分析使用了三口井。有两口井的产量下降，而第三口井的产量没有明显下降。研究结果表明，如果这两口表现不佳的井采用OHGP完井，PI的下降将得到缓解。然而，如果第三口井在相同的井眼轨迹上作为OHGP完成，则无法实现增产。研究结果还表明，与优化CHFP的完井位置相比，最大限度地减少钻井损害是OHGP完井成功的关键。本文讨论了影响深水井PI下降的重要问题，并提出了一种基于替代完井类型的潜在补救技术。本文还提出了一种基于实验设计的新方法来评估各种损伤机制的贡献，同时结合基于现有测量的每种机制的不确定性。
{"title":"Assessing the Impact of Open Hole Gravel Pack Completions to Remediate the Observed Productivity Decline in Cased Hole FracPack Completions in Deepwater Gulf of Mexico Fields","authors":"K. Zaki, Yan Li, C. Terry","doi":"10.2118/191731-MS","DOIUrl":"https://doi.org/10.2118/191731-MS","url":null,"abstract":"\u0000 The objective of this work is to assess the impact on productivity decline of altering the completion type in a deepwater Miocene reservoir. Typically to date, these types of assets have utilized Cased Hole FracPack (CHFP) completions as a basis of design. Wells in the Gulf of Mexico targeting the deepwater Miocene plays have seen significant Productivity Index (PI) decline within the first few years of production.\u0000 Open Hole Gravel Pack (OHGP) and Open Hole FracPack (OHFP) completion types were selected as potential alternatives to CHFP. A coupled well, reservoir and geomechanical model was created to assess the impact of multiple potential damage components on matching the observed inflow performance from production logs. The model assesses probabilistically the weighting of each of six damage mechanisms (creep, fracture conductivity, fines migration, fracture connectivity, off-plane perforation contribution and drilling/completion fluid damage) on well performance. Based on this weighting, an assessment can then be made of their impact on the alternate completion types.\u0000 Previous studies (Knobles et al. 2017) have indicated that cased hole completions are particularly susceptible to PI decline. Specifically, when unpropped perforation tunnels collapse, they reduce the inflow area into the wellbore and create a flow restriction. In higher permeability formations, the perforations not connected to the fracture (i.e. off-plane perforations) can contribute a significant portion of the well's production. It is important to note that if the connectivity and packing of the perforations is optimized and fracture is placed to within design specifications, little PI decline is observed. However, in the real world, this is not always the case. Three wells were used in this analysis. Two wells where decline was observed and a third well where no significant decline was observed. Results from the study indicated that if the two underperforming wells had utilized an OHGP completion, the PI degradation would have been mitigated. However, the upside production seen from the third well would not be attainable had the well been completed as an OHGP on an equivalent well trajectory. The results of the study also indicated that minimizing the drilling damage would be integral to the success of the OHGP completion in comparison to optimizing the completion placement in a CHFP.\u0000 The paper addresses a significant issue of PI decline affecting deepwater wells and presents a potential remediation technique based on alternate completion types. The paper also presents a new methodology based on Design of Experiment to assess the contribution of various damage mechanism while incorporating the uncertainty around each based on available measurements.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75549777","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}
Oil recovery during waterflooding of carbonate reservoirs is often low due to their oil-wetness and heterogeneity. Surfactant-Polymer (SP) flooding can improve the oil recovery from these reservoirs through ultra-low interfacial tension (IFT), mobility control and wettability alteration. However, there are several challenges associated with this process in high salinity and high temperature carbonate reservoirs related to thermal stability of polymers at elevated temperatures, compatibility of surfactants with high concentration of divalent cations present in formation brines, and geochemical interactions with carbonate minerals. This paper addresses the following challenges: surfactant interaction with formation brine containing high concentration of divalent cations and thermal stability and transport of polymers in carbonate rocks at a high temperature (80 C). Surfactant phase behavior experiments were performed to identify promising surfactant candidates which showed ultralow IFT with crude oil and aqueous stability at high temperature in high salinity and high hardness brines. A systematic study was performed to understand the effect of surfactant hydrophobe length on phase behavior, oil recovery, and surfactant retention in coreflood experiments. Novel surfactants with very short hydrophobes and cosolvent-like properties were also included to further optimize the phase behavior. Surfactants of larger hydrophobe length, containing similar number of EO and PO groups, gave higher solubilization ratio (and lower IFT) and lower optimum salinity. Specialty synthetic polymers with good thermal stability and salinity tolerance (TDS > 90,000 ppm) were investigated for their transport in single-phase corefloods. Results showed successful transport of polymer, without degradation in-situ, and improvement in mobility control. SP core floods were conducted using selected formulations in Indiana limestone cores. Coreflood experiments showed small increases in oil recovery over waterflood after the injection of the chemical formulation. Succesful polymer transport was observed in SP corefloods at high temperature.
{"title":"Development of Surfactant-Polymer SP Processes for High Temperature and High Salinity Carbonate Reservoirs","authors":"P. Ghosh, H. Sharma, K. Mohanty","doi":"10.2118/191733-MS","DOIUrl":"https://doi.org/10.2118/191733-MS","url":null,"abstract":"\u0000 Oil recovery during waterflooding of carbonate reservoirs is often low due to their oil-wetness and heterogeneity. Surfactant-Polymer (SP) flooding can improve the oil recovery from these reservoirs through ultra-low interfacial tension (IFT), mobility control and wettability alteration. However, there are several challenges associated with this process in high salinity and high temperature carbonate reservoirs related to thermal stability of polymers at elevated temperatures, compatibility of surfactants with high concentration of divalent cations present in formation brines, and geochemical interactions with carbonate minerals. This paper addresses the following challenges: surfactant interaction with formation brine containing high concentration of divalent cations and thermal stability and transport of polymers in carbonate rocks at a high temperature (80 C). Surfactant phase behavior experiments were performed to identify promising surfactant candidates which showed ultralow IFT with crude oil and aqueous stability at high temperature in high salinity and high hardness brines. A systematic study was performed to understand the effect of surfactant hydrophobe length on phase behavior, oil recovery, and surfactant retention in coreflood experiments. Novel surfactants with very short hydrophobes and cosolvent-like properties were also included to further optimize the phase behavior. Surfactants of larger hydrophobe length, containing similar number of EO and PO groups, gave higher solubilization ratio (and lower IFT) and lower optimum salinity. Specialty synthetic polymers with good thermal stability and salinity tolerance (TDS > 90,000 ppm) were investigated for their transport in single-phase corefloods. Results showed successful transport of polymer, without degradation in-situ, and improvement in mobility control. SP core floods were conducted using selected formulations in Indiana limestone cores. Coreflood experiments showed small increases in oil recovery over waterflood after the injection of the chemical formulation. Succesful polymer transport was observed in SP corefloods at high temperature.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73816884","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}
Jingyang Pu, Baojuri Jun Bai, Ali K. Alhuraishawy, T. Schuman, Yashu Chen, Xindi Sun
Preformed particle gels (PPG) have been successfully applied to control conformance for mature oilfields due to its advantages over conventional in-situ gels. However, field applications have demonstrated that current particle gels cannot efficiently plug opening fractures, fractures-like channels, or conduits which exist in many mature oilfields. The objective of this study is to systematically evaluate a new re-crosslinkable preformed particle gel (RPPG) product which can be used to efficiently control the conformance for the abnormal features. The novel particle gels can re-crosslink to form a rubber-like bulky material in the large opening features after placement to significantly enhance the plugging efficiency. We systematically evaluated the effect of temperature, brine concentration and RPPG swelling ratio on the re-crosslinking time, the gel strength after crosslinking, and their thermos-stability. Core flooding tests were run to test whether RPPG can significantly improve the fracture plugging efficiency comparing to a traditional PPG which cannot re-crosslink after pumping. The RPPG can be customized for the mature reservoirs with the temperature from 23 to 80°C with controllable size from tens of nanometer to a few millimeters. The RPPG swelling ratio can be controlled from 5 to 40 times. Its re-crosslinking time can be controlled from 2 to 80 h, depending on absorbed water amount, brine concentration, and temperature. The gel elastic modulus after re-crosslinking can achieve from 300 to 10,800 Pa, depending on swelling ratio. Core flooding tests showed that the breakthrough pressure of the re-crosslinked RPPG can reach up to 300 psi/ft for the fracture with the width of 5 cm and 0.2 cm aperture, which is more than 5 times higher than traditional PPGs. In addition, the plugging efficiency of the RPPG is 20 times higher than 40 K.
{"title":"A Novel Re-Crosslinkable Preformed Particle Gel for Conformance Control in Extreme Heterogeneous Reservoirs","authors":"Jingyang Pu, Baojuri Jun Bai, Ali K. Alhuraishawy, T. Schuman, Yashu Chen, Xindi Sun","doi":"10.2118/191697-MS","DOIUrl":"https://doi.org/10.2118/191697-MS","url":null,"abstract":"\u0000 Preformed particle gels (PPG) have been successfully applied to control conformance for mature oilfields due to its advantages over conventional in-situ gels. However, field applications have demonstrated that current particle gels cannot efficiently plug opening fractures, fractures-like channels, or conduits which exist in many mature oilfields. The objective of this study is to systematically evaluate a new re-crosslinkable preformed particle gel (RPPG) product which can be used to efficiently control the conformance for the abnormal features. The novel particle gels can re-crosslink to form a rubber-like bulky material in the large opening features after placement to significantly enhance the plugging efficiency. We systematically evaluated the effect of temperature, brine concentration and RPPG swelling ratio on the re-crosslinking time, the gel strength after crosslinking, and their thermos-stability. Core flooding tests were run to test whether RPPG can significantly improve the fracture plugging efficiency comparing to a traditional PPG which cannot re-crosslink after pumping. The RPPG can be customized for the mature reservoirs with the temperature from 23 to 80°C with controllable size from tens of nanometer to a few millimeters. The RPPG swelling ratio can be controlled from 5 to 40 times. Its re-crosslinking time can be controlled from 2 to 80 h, depending on absorbed water amount, brine concentration, and temperature. The gel elastic modulus after re-crosslinking can achieve from 300 to 10,800 Pa, depending on swelling ratio. Core flooding tests showed that the breakthrough pressure of the re-crosslinked RPPG can reach up to 300 psi/ft for the fracture with the width of 5 cm and 0.2 cm aperture, which is more than 5 times higher than traditional PPGs. In addition, the plugging efficiency of the RPPG is 20 times higher than 40 K.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84853690","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}
Non-radioactive tracer tagged proppant technology has been used successfully in over 200 vertical wells to obtain fracture height and gravel pack coverage, but had yet to be modeled or tested in horizontal wells, where the borehole and fracture geometry is radically different. The purpose of this paper is to demonstrate the effectiveness of this new technology to locate proppant placement and to evaluate the efficiency of perforations and clustering in fracturing operations in horizontal wells. The new technology utilizes a pulsed neutron capture (PNC) logging tool to detect the tagged proppant, which has a high thermal neutron capture cross-section. Monte Carlo software is utilized to simulate the responses of different pulsed neutron measurements to vertical fracture planes along a horizontal wellbore. The tool responses were analyzed and the best PNC measurement parameters were determined for locating proppant placement in the fractures, and hence for determining perforation and cluster efficiency. A field test was the conducted to validate modeling results in a horizontal well with multi-stage fracturing operations. Modeling data and the field log example show that it is feasible to use the taggant and a PNC tool to locate proppant placement and determine the efficiency of perforations and clustering in horizontal wells. Furthermore, the analysis of the depth intervals of tracer signals and the known axial and radial resolutions of the PNC measurements show that the depth interval of tracer signals along the wellbore may provide a qualitative indicator of one or more of the following: (1) the presence of multiple fractures opposite perforation(s), (2) the angle between the wellbore axis and the fracture plane for ideal conditions (e.g. the more narrow the tracer signal along the log, the closer the fracture plane is to being perpendicular to the wellbore axis), and/or (3) proppant placement in the borehole region. Moreover, a new near-wellbore connectivity index has been developed based on identifying and using the most suitable PNC log parameters for the evaluation. The index indicates how well the induced fracture is connected to the wellbore at locations of all perforations/clusters. The field test demonstrated that this new technology met all of the operator's objectives, with tracer signals clearly observed in all stages. This paper will present the modeling work and the results from the field test. The new non-radioactive proppant tracer technology provides for the first time the ability to evaluate proppant location in horizontal wells without encountering the health, safety, and environmental issues associated with using radioactive tracers. The determination of proppant placement and perforation efficiency, and a near-wellbore connectivity index, can be employed to evaluate the success and effectiveness of individual perforations and stages, and to optimize future completion designs and processes for enhancing hydrocarbon recove
{"title":"A Novel Technology for Locating and Evaluating Hydraulic Fractures in Horizontal Wells – Modeling and Field Results","authors":"Jeremy Zhang, Harry Smith, T. Palisch, L. Reynaud","doi":"10.2118/191707-MS","DOIUrl":"https://doi.org/10.2118/191707-MS","url":null,"abstract":"\u0000 Non-radioactive tracer tagged proppant technology has been used successfully in over 200 vertical wells to obtain fracture height and gravel pack coverage, but had yet to be modeled or tested in horizontal wells, where the borehole and fracture geometry is radically different. The purpose of this paper is to demonstrate the effectiveness of this new technology to locate proppant placement and to evaluate the efficiency of perforations and clustering in fracturing operations in horizontal wells.\u0000 The new technology utilizes a pulsed neutron capture (PNC) logging tool to detect the tagged proppant, which has a high thermal neutron capture cross-section. Monte Carlo software is utilized to simulate the responses of different pulsed neutron measurements to vertical fracture planes along a horizontal wellbore. The tool responses were analyzed and the best PNC measurement parameters were determined for locating proppant placement in the fractures, and hence for determining perforation and cluster efficiency. A field test was the conducted to validate modeling results in a horizontal well with multi-stage fracturing operations.\u0000 Modeling data and the field log example show that it is feasible to use the taggant and a PNC tool to locate proppant placement and determine the efficiency of perforations and clustering in horizontal wells. Furthermore, the analysis of the depth intervals of tracer signals and the known axial and radial resolutions of the PNC measurements show that the depth interval of tracer signals along the wellbore may provide a qualitative indicator of one or more of the following: (1) the presence of multiple fractures opposite perforation(s), (2) the angle between the wellbore axis and the fracture plane for ideal conditions (e.g. the more narrow the tracer signal along the log, the closer the fracture plane is to being perpendicular to the wellbore axis), and/or (3) proppant placement in the borehole region. Moreover, a new near-wellbore connectivity index has been developed based on identifying and using the most suitable PNC log parameters for the evaluation. The index indicates how well the induced fracture is connected to the wellbore at locations of all perforations/clusters. The field test demonstrated that this new technology met all of the operator's objectives, with tracer signals clearly observed in all stages. This paper will present the modeling work and the results from the field test.\u0000 The new non-radioactive proppant tracer technology provides for the first time the ability to evaluate proppant location in horizontal wells without encountering the health, safety, and environmental issues associated with using radioactive tracers. The determination of proppant placement and perforation efficiency, and a near-wellbore connectivity index, can be employed to evaluate the success and effectiveness of individual perforations and stages, and to optimize future completion designs and processes for enhancing hydrocarbon recove","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91085777","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}
Verification and testing of a newly installed wellbore barrier, in older assets has proven to be challenging. Even more so when the well has structural issues, indemnities or weak spots in the barrier envelope, or weakend well construction that limits the possibility to acheive a positive pressure verification of the barrier with an applied surface pressure versus the reservoir pressure. A suitable location with necessary support and strength should be located in the well. If installing a mechanical barrier in means of a bridge plug as the primary barrier, we will monitor the installation forces in the anchoring and sealing sequence. This individual signature will be verified towards a nominal base line signature of a ISO approved test and a library of thousands of collected installation profiles. Any abnormality can trigger a release and relocating of the barrier. A second verification barrier will then be installed close above the primary barrier and installation sequence will be verified the same way as the primary barrier. When both installation signatures are accounted for we can pressure test the installed barriers. This can be done with a pressure manipulation tool, where we introduce a calculated predetermined pressure drop between the installed primary barrier and the verification barrier above. By monitoring this pressure alteration vs. the pressure above the verification barrier, we can determine if we have a verified primary and verification barrier. The Primary Barrier is verified in the direction of flow (negative pressure test). And verification barrier as the secondary barrier is verified with a positive pressure test. If a dual barrier is requested you can leave the verification barrier as secondary barrier or pull to re-use.
{"title":"A Novel Approach to Barrier Integrity Testing in Well","authors":"Arild F. Stein","doi":"10.2118/191664-MS","DOIUrl":"https://doi.org/10.2118/191664-MS","url":null,"abstract":"\u0000 Verification and testing of a newly installed wellbore barrier, in older assets has proven to be challenging. Even more so when the well has structural issues, indemnities or weak spots in the barrier envelope, or weakend well construction that limits the possibility to acheive a positive pressure verification of the barrier with an applied surface pressure versus the reservoir pressure.\u0000 A suitable location with necessary support and strength should be located in the well. If installing a mechanical barrier in means of a bridge plug as the primary barrier, we will monitor the installation forces in the anchoring and sealing sequence. This individual signature will be verified towards a nominal base line signature of a ISO approved test and a library of thousands of collected installation profiles. Any abnormality can trigger a release and relocating of the barrier. A second verification barrier will then be installed close above the primary barrier and installation sequence will be verified the same way as the primary barrier. When both installation signatures are accounted for we can pressure test the installed barriers. This can be done with a pressure manipulation tool, where we introduce a calculated predetermined pressure drop between the installed primary barrier and the verification barrier above. By monitoring this pressure alteration vs. the pressure above the verification barrier, we can determine if we have a verified primary and verification barrier.\u0000 The Primary Barrier is verified in the direction of flow (negative pressure test). And verification barrier as the secondary barrier is verified with a positive pressure test. If a dual barrier is requested you can leave the verification barrier as secondary barrier or pull to re-use.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"107 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79621427","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 capacitance-resistance model (CRM) is an analytical tool that uses only injection and production rate to quantify interwell connectivity and response time during a waterflood. It has been widely used in conventional waterfloods for reservoir characterization, performance evaluation and optimization. Heavy oil waterfloods introduce challenges to the application of CRM due to the high mobility ratio and its rapid variation as a function of waterflood maturity. Using conceptual reservoir models and sensitivity studies, we provide guidelines for application of CRM in heavy oil waterfloods. We illustrate our approach in two heavy oil fields under waterflood. In heavy oil waterfloods, it is observed that interwell connectivity and response time varied over time, especially right before and after water breakthrough. The magnitude of CRM parameter variation is a function of viscosity ratio between water and oil, flood maturity, and contrast of flow and storage capacity of the flow units. Case studies of heavy oil watetrflood (one mature, one immature) showed that CRM can be used for waterflood analysis, and forecasting. In the immature flood with one injector and two producers and high permeability contrast, the most extreme variation of CRM parameters was observed. In the pattern flood where injected fluid was distributed relatively evenly among producers and breakthrough had already occurred, the CRM parameters tended to be constant over time. We showed that with frequent analysis (window approach) CRM can be efficiently used in heavy oil waterfloods,
{"title":"Heavy Oil Waterflood Application of Capacitance Resistance Models","authors":"Tiantian Zhang, O. Izgec, M. Sayarpour","doi":"10.2118/191398-MS","DOIUrl":"https://doi.org/10.2118/191398-MS","url":null,"abstract":"\u0000 The capacitance-resistance model (CRM) is an analytical tool that uses only injection and production rate to quantify interwell connectivity and response time during a waterflood. It has been widely used in conventional waterfloods for reservoir characterization, performance evaluation and optimization. Heavy oil waterfloods introduce challenges to the application of CRM due to the high mobility ratio and its rapid variation as a function of waterflood maturity. Using conceptual reservoir models and sensitivity studies, we provide guidelines for application of CRM in heavy oil waterfloods. We illustrate our approach in two heavy oil fields under waterflood.\u0000 In heavy oil waterfloods, it is observed that interwell connectivity and response time varied over time, especially right before and after water breakthrough. The magnitude of CRM parameter variation is a function of viscosity ratio between water and oil, flood maturity, and contrast of flow and storage capacity of the flow units. Case studies of heavy oil watetrflood (one mature, one immature) showed that CRM can be used for waterflood analysis, and forecasting. In the immature flood with one injector and two producers and high permeability contrast, the most extreme variation of CRM parameters was observed. In the pattern flood where injected fluid was distributed relatively evenly among producers and breakthrough had already occurred, the CRM parameters tended to be constant over time. We showed that with frequent analysis (window approach) CRM can be efficiently used in heavy oil waterfloods,","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75233895","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}
Residual oil zones (ROZs) are defined as those zones where oil is swept over geologic time period (natural flush) and exists at residual saturation. ROZs are increasingly being commercially exploited using CO2-enhanced oil recovery (EOR) (in Permian Basin). In this study, CO2 storage potential, long-term CO2 fate and oil recovery potential in ROZs are characterized. We use numerical simulations of CO2 injection with a reservoir model based on data from the Permian Basin. The changes of CO2 storage capacity and potential oil recovery with amount of CO2 injection are investigated. The effects of different well patterns (five-spot and line drive) and well spacing on fraction of CO2 retained in reservoir and cumulative oil production are also investigated. Furthermore, the effect of different CO2 injection modes, i.e., continuous CO2 injection and water-alternating-gas injection (WAG), on the CO2 storage and EOR potential are evaluated and compared. After the preliminary characterization of CO2 storage and EOR potential in ROZs, we next develop empirical models that can be used for estimating the CO2 storage capacity and oil production potential for different ROZs. A supervised machine learning algorithm, Multivariate Adaptive Regression Splines (MARS, (Jamali et al.)) is used for developing the empirical models. Results show that CO2 retention efficiency and oil recovery vary non-linearly with amount of CO2 injected. It is observed that long-term CO2 fate is a function of CO2 injection amount and significant fraction of reservoir CO2 resides in hydrocarbon phase. Five-spot well pattern results in more oil production and larger amount of CO2 retained in reservoir than line-drive well pattern. During the investigation of well spacing, we observe that less number of wells actually results in higher CO2 retention and oil recovery, and less number of wells can also result in less probability of wellbore leakage. In comparison of WAG and continuous CO2 injection modes, it is observed that WAG injection has higher fraction of injected CO2 retained in reservoir, but with slightly lower cumulative oil production. In the study of empirical models for the capacity assessment of CO2 storage and EOR, results show that MARS can generate high-fidelity empirical models that can be used to predict the cumulative CO2 storage capacity and cumulative oil production for different ROZs.
{"title":"Capacity Assessment of CO2 Storage and Enhanced Oil Recovery in Residual Oil Zones","authors":"Bailian Chen, R. Pawar","doi":"10.2118/191604-MS","DOIUrl":"https://doi.org/10.2118/191604-MS","url":null,"abstract":"\u0000 Residual oil zones (ROZs) are defined as those zones where oil is swept over geologic time period (natural flush) and exists at residual saturation. ROZs are increasingly being commercially exploited using CO2-enhanced oil recovery (EOR) (in Permian Basin). In this study, CO2 storage potential, long-term CO2 fate and oil recovery potential in ROZs are characterized. We use numerical simulations of CO2 injection with a reservoir model based on data from the Permian Basin. The changes of CO2 storage capacity and potential oil recovery with amount of CO2 injection are investigated. The effects of different well patterns (five-spot and line drive) and well spacing on fraction of CO2 retained in reservoir and cumulative oil production are also investigated. Furthermore, the effect of different CO2 injection modes, i.e., continuous CO2 injection and water-alternating-gas injection (WAG), on the CO2 storage and EOR potential are evaluated and compared. After the preliminary characterization of CO2 storage and EOR potential in ROZs, we next develop empirical models that can be used for estimating the CO2 storage capacity and oil production potential for different ROZs. A supervised machine learning algorithm, Multivariate Adaptive Regression Splines (MARS, (Jamali et al.)) is used for developing the empirical models.\u0000 Results show that CO2 retention efficiency and oil recovery vary non-linearly with amount of CO2 injected. It is observed that long-term CO2 fate is a function of CO2 injection amount and significant fraction of reservoir CO2 resides in hydrocarbon phase. Five-spot well pattern results in more oil production and larger amount of CO2 retained in reservoir than line-drive well pattern. During the investigation of well spacing, we observe that less number of wells actually results in higher CO2 retention and oil recovery, and less number of wells can also result in less probability of wellbore leakage. In comparison of WAG and continuous CO2 injection modes, it is observed that WAG injection has higher fraction of injected CO2 retained in reservoir, but with slightly lower cumulative oil production. In the study of empirical models for the capacity assessment of CO2 storage and EOR, results show that MARS can generate high-fidelity empirical models that can be used to predict the cumulative CO2 storage capacity and cumulative oil production for different ROZs.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73760538","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}
Present day innovations in seismic acquisition tools and techniques have enabled the acquisition of detailed seismic datasets, which in many cases are extremely large (on the order of terabytes to petabytes). However, data analysis tools for extracting information on critical subsurface features such as fractures are still evolving. Traditional methods rely on time-consuming iterative workflows, which involve computing seismic attributes, de-noising and expert interpretation. Additionally, with the increasingly widespread acquisition of time-lapse seismic surveys (4D), there is a heightened demand for reliable automated workflows to assist feature interpretation from seismic data. We present a novel data-driven tool for fast fracture identification in BIG post-stack seismic datasets, motivated by techniques developed for real-time face detection. The proposed algorithm computes spatiotemporal amplitude statistics using Haar-like bases, in order to characterize the seismic amplitude properties that correspond to fracture occurrence in a unit window or voxel. Under this approach, the amplitude data is decomposed into a collection of simple-to-calculate "mini-attributes", which carry information on the amplitude gradient and curvature characteristics at varying locations and scales. These features then serve as inputs to a cascade of boosted classification tree models, which select and combine the most discriminative features to develop a probabilistic binary classification model. This overall approach helps to eliminate the computationally-intensive and subjective use of ad-hoc seismic attributes in existing approaches. We first demonstrate the viability of the proposed methodology for identifying discrete macro-fractures in a 2D synthetic seismic dataset. Next, we validate the approach using 3D post-stack seismic data from the Niobrara Shale interval within the Teapot Dome field. We show the applicability of the proposed framework for identifying sub-seismic fractures, by considering the amplitude profile adjacent to interpreted fullbore microimage (FMI) well log data. The upscaled spatial distribution of the predicted fractures shows agreement with existing geological studies and align with interpreted large-scale faults within the interval of interest.
{"title":"Big Data Analytics for Seismic Fracture Identification, Using Amplitude-Based Statistics","authors":"E. Udegbe, E. Morgan, S. Srinivasan","doi":"10.2118/191668-MS","DOIUrl":"https://doi.org/10.2118/191668-MS","url":null,"abstract":"\u0000 Present day innovations in seismic acquisition tools and techniques have enabled the acquisition of detailed seismic datasets, which in many cases are extremely large (on the order of terabytes to petabytes). However, data analysis tools for extracting information on critical subsurface features such as fractures are still evolving. Traditional methods rely on time-consuming iterative workflows, which involve computing seismic attributes, de-noising and expert interpretation. Additionally, with the increasingly widespread acquisition of time-lapse seismic surveys (4D), there is a heightened demand for reliable automated workflows to assist feature interpretation from seismic data.\u0000 We present a novel data-driven tool for fast fracture identification in BIG post-stack seismic datasets, motivated by techniques developed for real-time face detection. The proposed algorithm computes spatiotemporal amplitude statistics using Haar-like bases, in order to characterize the seismic amplitude properties that correspond to fracture occurrence in a unit window or voxel. Under this approach, the amplitude data is decomposed into a collection of simple-to-calculate \"mini-attributes\", which carry information on the amplitude gradient and curvature characteristics at varying locations and scales. These features then serve as inputs to a cascade of boosted classification tree models, which select and combine the most discriminative features to develop a probabilistic binary classification model. This overall approach helps to eliminate the computationally-intensive and subjective use of ad-hoc seismic attributes in existing approaches.\u0000 We first demonstrate the viability of the proposed methodology for identifying discrete macro-fractures in a 2D synthetic seismic dataset. Next, we validate the approach using 3D post-stack seismic data from the Niobrara Shale interval within the Teapot Dome field. We show the applicability of the proposed framework for identifying sub-seismic fractures, by considering the amplitude profile adjacent to interpreted fullbore microimage (FMI) well log data. The upscaled spatial distribution of the predicted fractures shows agreement with existing geological studies and align with interpreted large-scale faults within the interval of interest.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80596804","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}
Dalia Abdallah, Sameer Punnapala, Omar Kulbrandstad, M. Godoy, Sai Madem, A. Babakhani, John Lovell
The selection of optimal chemical solutions to an asphaltene challenge has been an integral part of the flow assurance strategy for a large on-shore field in Abu Dhabi. Previous studies in the field have demonstrated good performance by mixing heavy aromatic naphtha with some dispersant chemicals and then bull-heading that mix to allow it to soak and then flow back. Laboratory studies using dispersant tests were performed to better understand the effectiveness of carrier solvent and dispersant mixtures; the economics of different fluid delivery methods (jet blasting, bull-heading, etc.) were analyzed for cost-effectiveness; and significant field-testing was performed to validate the integrated approach. But despite all of this activity, there was still no direct measurement. Inferences of asphaltene removal or redeposition needed to be made from indirect sources such as surface pressure gauges and flow meters or via intervention, such as running an accessibility check using gauge cutters. There was no hardware available in the industry for direct measurement of the asphaltene. This led the operating company to help sponsor development of a real-time sensor. A ruggedized version of that sensor has now completed its first field-test in Abu Dhabi. The physics behind the sensor relies on the use of a known quantum property of asphaltene, namely that asphaltene free-radicals can be resonated by an external magnetic field with a particular ratio of frequency to magnetic field strength, a phenomenon known as Electron Paramagnetic Resonance (EPR). Contributions from metal ions such as nickel, manganese, iron and vanadium can also be resonated. Spectrometers using the EPR effect have been used, for example, in the geochemical industry for concentration analysis of organic free matter, but only inside dedicated laboratories. To take the asphaltene study to the next level, real-time data would be needed directly from the wellhead. By focusing primarily on the asphaltene response, rather than a broad range of chemicals, it proved possible to miniature and ruggedize the device for oilfield application. Fluid can enter and leave the device via side-streams from the main flowline. The spectral output gives a direct measurement of spin concentration and hence the percentage of asphaltene flowing past. The goal of the first field test was to validate the device resolution in a field application. It is known from previous laboratory and field data that the total asphaltene ratio would be less than 1%, so the EPR signal might be anticipated to be small. Results exceeded expectations and repeatability was better than 0.1%. One initial surprise was that the asphaltene level in each well changed over time, even during steady production. Some wells showed significant variation from one day to the next with a standard deviation near 5%. Other wells showed barely 1% variation. The wells with the higher standard deviation seemed to correlate against those wells which
{"title":"Asphaltene Studies in On-Shore Abu Dhabi Fields, Part IV: Development of a Surface Sensor","authors":"Dalia Abdallah, Sameer Punnapala, Omar Kulbrandstad, M. Godoy, Sai Madem, A. Babakhani, John Lovell","doi":"10.2118/191676-MS","DOIUrl":"https://doi.org/10.2118/191676-MS","url":null,"abstract":"\u0000 The selection of optimal chemical solutions to an asphaltene challenge has been an integral part of the flow assurance strategy for a large on-shore field in Abu Dhabi. Previous studies in the field have demonstrated good performance by mixing heavy aromatic naphtha with some dispersant chemicals and then bull-heading that mix to allow it to soak and then flow back. Laboratory studies using dispersant tests were performed to better understand the effectiveness of carrier solvent and dispersant mixtures; the economics of different fluid delivery methods (jet blasting, bull-heading, etc.) were analyzed for cost-effectiveness; and significant field-testing was performed to validate the integrated approach. But despite all of this activity, there was still no direct measurement. Inferences of asphaltene removal or redeposition needed to be made from indirect sources such as surface pressure gauges and flow meters or via intervention, such as running an accessibility check using gauge cutters. There was no hardware available in the industry for direct measurement of the asphaltene. This led the operating company to help sponsor development of a real-time sensor. A ruggedized version of that sensor has now completed its first field-test in Abu Dhabi.\u0000 The physics behind the sensor relies on the use of a known quantum property of asphaltene, namely that asphaltene free-radicals can be resonated by an external magnetic field with a particular ratio of frequency to magnetic field strength, a phenomenon known as Electron Paramagnetic Resonance (EPR). Contributions from metal ions such as nickel, manganese, iron and vanadium can also be resonated. Spectrometers using the EPR effect have been used, for example, in the geochemical industry for concentration analysis of organic free matter, but only inside dedicated laboratories. To take the asphaltene study to the next level, real-time data would be needed directly from the wellhead.\u0000 By focusing primarily on the asphaltene response, rather than a broad range of chemicals, it proved possible to miniature and ruggedize the device for oilfield application. Fluid can enter and leave the device via side-streams from the main flowline. The spectral output gives a direct measurement of spin concentration and hence the percentage of asphaltene flowing past.\u0000 The goal of the first field test was to validate the device resolution in a field application. It is known from previous laboratory and field data that the total asphaltene ratio would be less than 1%, so the EPR signal might be anticipated to be small. Results exceeded expectations and repeatability was better than 0.1%. One initial surprise was that the asphaltene level in each well changed over time, even during steady production. Some wells showed significant variation from one day to the next with a standard deviation near 5%. Other wells showed barely 1% variation. The wells with the higher standard deviation seemed to correlate against those wells which","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73655933","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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