The increasing demand for hydrocarbon made it a challenge to maintain the oil production and maximize recoverable reserves in mature fields. Interconnected flowline surface network, of oil producing wells, varying in reservoir pressure, connected to a single processing facility, resulted in network bottlenecks and other flow assurance issues. This study objective is to predict the temperature changing effect on hydraulic flow behavior and optimize the most precise multiphase flow correlation for the selected fields. The severity of bottlenecks can be profoundly affected by seasonal temperature changes, which require studying and pre-planning to reduce or avoid production losses. A flowline network model had been built and analyzed in-house using a commercial steady-state multiphase flow simulator for one of company's Gathering Centres (GC). GC-XY problematic, high pressure, headers were considered, which are receiving production from several fields in Kuwait. For representative results; comparisons were done for the prediction of multiphase flow correlations in horizontal and inclined pipelines. The predictions of the Beggs & Brill (1975), the Baker & Gabb (1988), the Dukler et al. (1969), the Mukherjee and Brill (1983), and the Oliemans (1976) correlations and the Xiao (1990) mechanistic model were evaluated in this study. The comparison was limited to a temperature range from −5 to 55 Celsius degrees, light oil with API above or equal 30 degrees, and 6 inches flowline inner diameter. The study displays statistical error comparison between the predictions of each multiphase flow model used and suggests a correlation for the applied conditions in the selected field. Bottlenecks had been found in the network model, and a variety of solutions were proposed and simulated to overcome the bottleneck severity due to temperature changes. The results findings show a significate potential is reducing the bottlenecks severity up to 40 percent in the designed network and production enhancement of 18,000 barrels daily. Detailed criteria and calculations were stated to compare and select the most accurate multiphase flow correlations for the chosen fields. Also, the project explains a procedure to model the suggested solutions and find the expected enhancement of production. Temperature overestimation can lead to severe bottlenecks, which require dedicated and reliable studies to minimize the losses due to heat transfer effect on oil viscosity and flow behavior.
{"title":"The Temperature Effect on Selecting a Precise Multiphase Flow Correlation to Find Bottlenecks in Production Surface Network Model in Kuwaiti Fields","authors":"H. Almohammad","doi":"10.2118/193225-MS","DOIUrl":"https://doi.org/10.2118/193225-MS","url":null,"abstract":"\u0000 The increasing demand for hydrocarbon made it a challenge to maintain the oil production and maximize recoverable reserves in mature fields. Interconnected flowline surface network, of oil producing wells, varying in reservoir pressure, connected to a single processing facility, resulted in network bottlenecks and other flow assurance issues. This study objective is to predict the temperature changing effect on hydraulic flow behavior and optimize the most precise multiphase flow correlation for the selected fields.\u0000 The severity of bottlenecks can be profoundly affected by seasonal temperature changes, which require studying and pre-planning to reduce or avoid production losses. A flowline network model had been built and analyzed in-house using a commercial steady-state multiphase flow simulator for one of company's Gathering Centres (GC). GC-XY problematic, high pressure, headers were considered, which are receiving production from several fields in Kuwait. For representative results; comparisons were done for the prediction of multiphase flow correlations in horizontal and inclined pipelines.\u0000 The predictions of the Beggs & Brill (1975), the Baker & Gabb (1988), the Dukler et al. (1969), the Mukherjee and Brill (1983), and the Oliemans (1976) correlations and the Xiao (1990) mechanistic model were evaluated in this study. The comparison was limited to a temperature range from −5 to 55 Celsius degrees, light oil with API above or equal 30 degrees, and 6 inches flowline inner diameter. The study displays statistical error comparison between the predictions of each multiphase flow model used and suggests a correlation for the applied conditions in the selected field. Bottlenecks had been found in the network model, and a variety of solutions were proposed and simulated to overcome the bottleneck severity due to temperature changes. The results findings show a significate potential is reducing the bottlenecks severity up to 40 percent in the designed network and production enhancement of 18,000 barrels daily.\u0000 Detailed criteria and calculations were stated to compare and select the most accurate multiphase flow correlations for the chosen fields. Also, the project explains a procedure to model the suggested solutions and find the expected enhancement of production. Temperature overestimation can lead to severe bottlenecks, which require dedicated and reliable studies to minimize the losses due to heat transfer effect on oil viscosity and flow behavior.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90996848","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}
Near-surface characterization is an important part of seismic data processing, especially with land seismic data. The conventional approaches rely on refracted waves and estimate the compressional velocity models from the tomography of the first-break traveltimes (Glushchenko et al., 2012, Speziali et al., 2014). Despite its strong ability to image the subsurface, seismic tomography is a non-unique inverse problem (Kanlı, 2009, Mantovani et al. 2013). Because most inverse geophysical problems are non-unique, each problem must be studied to determine what type of non-uniqueness applies and, thus, determine what type of a-priori information is necessary to find a realistic solution (Ivanov et al., 2005). There are several ways to incorporate the available a-priori information in the inverse problem; one of them is the definition of the initial model, which is the starting point of the inversion process. In this work, we present a data-driven approach that derives the initial velocity model for a refraction tomography workflow in an automated fashion, thus trying to minimize the amount of subjectivity that influences the starting model definition (Osypov, 2001). We demonstrate the technique by mean of a synthetic, but realistic, 3D example.
近地表表征是地震资料处理，尤其是陆地地震资料处理的重要组成部分。传统方法依赖于折射波，并通过首波传播时间的断层扫描估计纵波速度模型(Glushchenko等，2012,Speziali等，2014)。尽管地震层析成像具有很强的地下成像能力，但它是一个非唯一的逆问题(kanlyi, 2009, Mantovani et al. 2013)。因为大多数逆地球物理问题都是非唯一性的，所以必须对每个问题进行研究，以确定适用哪种类型的非唯一性，从而确定需要哪种类型的先验信息来找到现实的解决方案(Ivanov等人，2005)。有几种方法可以将可用的先验信息合并到逆问题中;其中之一是初始模型的定义，它是反演过程的起点。在这项工作中，我们提出了一种数据驱动的方法，以自动化的方式导出折射层析成像工作流的初始速度模型，从而尽量减少影响初始模型定义的主观性(Osypov, 2001)。我们通过一个合成的，但现实的，3D的例子来演示该技术。
{"title":"A Data-Driven Technique for Building the Initial Velocity Model for Refraction Tomography","authors":"S. Re","doi":"10.2118/193041-MS","DOIUrl":"https://doi.org/10.2118/193041-MS","url":null,"abstract":"\u0000 Near-surface characterization is an important part of seismic data processing, especially with land seismic data. The conventional approaches rely on refracted waves and estimate the compressional velocity models from the tomography of the first-break traveltimes (Glushchenko et al., 2012, Speziali et al., 2014). Despite its strong ability to image the subsurface, seismic tomography is a non-unique inverse problem (Kanlı, 2009, Mantovani et al. 2013). Because most inverse geophysical problems are non-unique, each problem must be studied to determine what type of non-uniqueness applies and, thus, determine what type of a-priori information is necessary to find a realistic solution (Ivanov et al., 2005).\u0000 There are several ways to incorporate the available a-priori information in the inverse problem; one of them is the definition of the initial model, which is the starting point of the inversion process. In this work, we present a data-driven approach that derives the initial velocity model for a refraction tomography workflow in an automated fashion, thus trying to minimize the amount of subjectivity that influences the starting model definition (Osypov, 2001). We demonstrate the technique by mean of a synthetic, but realistic, 3D example.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"110 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87025277","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
H. Almuallim, L. Ganzer, H. Uematsu, S. Bellah, V. Vîrlan
Constructing reservoir models that are consistent with geophysical and geological static data is well understood. A persisting challenge is to condition such models to the available production dynamic data through the process of history-matching. A new algorithm is utilized to identify influencing grid-block properties based on analytical sensitivity calculations. The derived sensitivities allow efficient modification of grid-block properties and saturation functions to improve the history-match. This innovative approach preserves the geological model features, because changes are done at the grid-block level and are only as small as needed to achieve a good match. Usually, the number of parameters is so immense that engineers have to either restrict their attention to a small subset of the parameters (and likely missing crucial ones), or unnecessarily pay extremely high simulation costs. In this paper, we employ a new assisted history-matching technique that computes the parameter sensitivities analytically and for each grid-block. Here, the derivatives of the mismatch with respect to each parameter are rigorously computed based on the black-oil simulator's fluid flow equations. Hence, a single simulation run followed by a derivatives calculation session is sufficient to detect how each parameter affects the mismatch, and consequently, to decide how (or whether) to change each parameter to improve the match. This technique was successfully applied to history-match a mature oil field in the Middle East. Two sets of parameters are modified: The permeability in 3 directions per grid block, and relative permeability curves for about 50 saturation regions. The goal was to match water-cut for individual wells. With this analytical technique, excellent improvement in the match was achieved after only a dozen simulation runs and within a couple of days. Because the modifications are at the grid block level and minimal (only as and where needed), the technique preserves the original geological features of the model to a great extent. Eliminating the need of manual local modifications (e.g. box multipliers) is an important advantage of the method. The relative permeability curves have been tweaked successfully for numerous saturation regions using Corey model parameters. The ability to adjust many curves successfully using just a few simulation runs represents a significant advancement in the field of assisted history-matching.
{"title":"Advanced Assisted History Matching of a Large Mature Oil Field Based on a Huge Number of Grid-Block Level Parameters and Saturation Functions","authors":"H. Almuallim, L. Ganzer, H. Uematsu, S. Bellah, V. Vîrlan","doi":"10.2118/192780-MS","DOIUrl":"https://doi.org/10.2118/192780-MS","url":null,"abstract":"\u0000 Constructing reservoir models that are consistent with geophysical and geological static data is well understood. A persisting challenge is to condition such models to the available production dynamic data through the process of history-matching. A new algorithm is utilized to identify influencing grid-block properties based on analytical sensitivity calculations. The derived sensitivities allow efficient modification of grid-block properties and saturation functions to improve the history-match. This innovative approach preserves the geological model features, because changes are done at the grid-block level and are only as small as needed to achieve a good match.\u0000 Usually, the number of parameters is so immense that engineers have to either restrict their attention to a small subset of the parameters (and likely missing crucial ones), or unnecessarily pay extremely high simulation costs. In this paper, we employ a new assisted history-matching technique that computes the parameter sensitivities analytically and for each grid-block. Here, the derivatives of the mismatch with respect to each parameter are rigorously computed based on the black-oil simulator's fluid flow equations. Hence, a single simulation run followed by a derivatives calculation session is sufficient to detect how each parameter affects the mismatch, and consequently, to decide how (or whether) to change each parameter to improve the match.\u0000 This technique was successfully applied to history-match a mature oil field in the Middle East. Two sets of parameters are modified: The permeability in 3 directions per grid block, and relative permeability curves for about 50 saturation regions. The goal was to match water-cut for individual wells.\u0000 With this analytical technique, excellent improvement in the match was achieved after only a dozen simulation runs and within a couple of days. Because the modifications are at the grid block level and minimal (only as and where needed), the technique preserves the original geological features of the model to a great extent. Eliminating the need of manual local modifications (e.g. box multipliers) is an important advantage of the method. The relative permeability curves have been tweaked successfully for numerous saturation regions using Corey model parameters. The ability to adjust many curves successfully using just a few simulation runs represents a significant advancement in the field of assisted history-matching.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"668 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86727118","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. Alzaabi, L. Uzun, Erdinc Eker, H. Kazemi, E. Ozkan
As a result of shale oil and gas production success in the United States, development of shale resources elsewhere around the world has gained great interest. In the Middle East, where much of the world's conventional reserves are located, huge investments have been deployed to evaluate the potential of shale reservoirs. In this paper, we present an integrated reservoir characterization study of Shilaif shale formation in the United Arab Emirates, which includes an assessment of the primary production from a test well using a multi-phase, dual-porosity model. We also evaluated enhancing production performance via improved well completion. In characterizing Shilaif's unconventional shale reservoir potential, we developed an integrated plan and workflow that included gathering and assessing the geological, petrophysical, and production data from a horizontal exploration well. The data used in the workflow included well-logs, cores, completion information, and pressure transient and production data from the well. The analysis of pressure build-up data ensuing the rate-transient period provided an estimate of effective formation permeability, which is a unique aspect of this study because such tests are not routinely conducted in shale reservoirs. The hydraulic fracture stimulation had improved the effective permeability nearly two orders of magnitude compared to the matrix permeability from cores and well logs. For the ultimate assessment and future performance, we developed a multi-phase dual-porosity numerical model. The simulation model was used to history-match the production data of hydraulically fractured horizontal well in Shilaif formation and case studies were conducted to evaluate the production potential. For future development plans, it was determined that decreasing the fracture spacing from 250 feet to 150 feet was not economically feasible because the incremental production was around eight percent during the first year of production. Nonetheless, the simulation model indicated that Shilaif's large shale reservoirs may be viable for future development targets in the Middle East arena.
{"title":"Production Potential of Shilaif Formation in UAE Using an Integrated Reservoir Characterization Approach","authors":"M. Alzaabi, L. Uzun, Erdinc Eker, H. Kazemi, E. Ozkan","doi":"10.2118/192693-MS","DOIUrl":"https://doi.org/10.2118/192693-MS","url":null,"abstract":"\u0000 As a result of shale oil and gas production success in the United States, development of shale resources elsewhere around the world has gained great interest. In the Middle East, where much of the world's conventional reserves are located, huge investments have been deployed to evaluate the potential of shale reservoirs. In this paper, we present an integrated reservoir characterization study of Shilaif shale formation in the United Arab Emirates, which includes an assessment of the primary production from a test well using a multi-phase, dual-porosity model. We also evaluated enhancing production performance via improved well completion.\u0000 In characterizing Shilaif's unconventional shale reservoir potential, we developed an integrated plan and workflow that included gathering and assessing the geological, petrophysical, and production data from a horizontal exploration well. The data used in the workflow included well-logs, cores, completion information, and pressure transient and production data from the well. The analysis of pressure build-up data ensuing the rate-transient period provided an estimate of effective formation permeability, which is a unique aspect of this study because such tests are not routinely conducted in shale reservoirs. The hydraulic fracture stimulation had improved the effective permeability nearly two orders of magnitude compared to the matrix permeability from cores and well logs. For the ultimate assessment and future performance, we developed a multi-phase dual-porosity numerical model. The simulation model was used to history-match the production data of hydraulically fractured horizontal well in Shilaif formation and case studies were conducted to evaluate the production potential.\u0000 For future development plans, it was determined that decreasing the fracture spacing from 250 feet to 150 feet was not economically feasible because the incremental production was around eight percent during the first year of production. Nonetheless, the simulation model indicated that Shilaif's large shale reservoirs may be viable for future development targets in the Middle East arena.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89630757","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}
Sultan Dahi Al-Hassani, S. Ahmed, O. Khan, Ibrahim Mohamed AL-Tameemi, Shahnawaz Khan, P. Marza, J. Abdulrahim, S. Shasmal, M. Alexander
Reservoirs located offshore Abu Dhabi can be complex in terms of sub-seismic structural features such as faults and localized deformations. With use of high-resolution resistivity image logs, a TST (true stratigraphic thickness) technique, along with 3D structural models, uncertainties related to sub seismic structural ambiguities are resolved and well trajectory is optimized while drilling. In this case study, real-time resistivity image logs were used while drilling. The sinusoid’s shape on images provided cutting down dip or up dip information. Dip trends were analyzed using a dip vector plot and to identify zones-of-interest. Dip attribute along with the log response were compared with the pre-job model and the inclination is adjusted accordingly during drilling. Several high angle features can be characterized as stratigraphic changes, fractures, or faults. The morphology and trend change observed in the dip vector plot of these features lead to the conclusion that these are sub-seismic resolution faults and deformation is associated with the fault. The stratigraphic drilling polarity and the TST were calculated using the formation dip data. Using a TST scale and splitting the logs into stratigraphic drilling polarity domains, the fault throw displacement is estimated. The model is updated to reflect the interpreted data. The fault plunge and trend are extrapolated away from the wellbore and to nearby wells.
{"title":"Sub Seismic Fault Identification within Carbonate Reservoirs with Borehole Images Logging-While-Drilling: Integrated Approach in Optimizing Well Placement; A Case Study from Offshore Abu Dhabi","authors":"Sultan Dahi Al-Hassani, S. Ahmed, O. Khan, Ibrahim Mohamed AL-Tameemi, Shahnawaz Khan, P. Marza, J. Abdulrahim, S. Shasmal, M. Alexander","doi":"10.2118/192882-MS","DOIUrl":"https://doi.org/10.2118/192882-MS","url":null,"abstract":"\u0000 Reservoirs located offshore Abu Dhabi can be complex in terms of sub-seismic structural features such as faults and localized deformations. With use of high-resolution resistivity image logs, a TST (true stratigraphic thickness) technique, along with 3D structural models, uncertainties related to sub seismic structural ambiguities are resolved and well trajectory is optimized while drilling.\u0000 In this case study, real-time resistivity image logs were used while drilling. The sinusoid’s shape on images provided cutting down dip or up dip information. Dip trends were analyzed using a dip vector plot and to identify zones-of-interest. Dip attribute along with the log response were compared with the pre-job model and the inclination is adjusted accordingly during drilling. Several high angle features can be characterized as stratigraphic changes, fractures, or faults. The morphology and trend change observed in the dip vector plot of these features lead to the conclusion that these are sub-seismic resolution faults and deformation is associated with the fault.\u0000 The stratigraphic drilling polarity and the TST were calculated using the formation dip data. Using a TST scale and splitting the logs into stratigraphic drilling polarity domains, the fault throw displacement is estimated. The model is updated to reflect the interpreted data. The fault plunge and trend are extrapolated away from the wellbore and to nearby wells.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89963473","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}
Ahmed El Hawy, Adil Al Busaidi, R. Bautista, M. Awadallah, M. R. Heidari, K. Saidi, Barton Escamilla, Zahra Al Abri, Guy deBoehmler, S. Harthi, Patrick A C M Haeser, Khaleel Al Riyami, Mahesh S. Picha
As one of the worst oil & gas business downturns struck, the need for a revolutionary approach of drilling was needed. Optimization was the key word during that period, it was about time to look back at drilling fundamentals, review and learn from previous failures and lessons while establishing new foundation for a transformed yet successful process that ensured an all-time historical success. While many trials of drilling optimization initiatives were executed over the years, inconsistent drilling performance delivery and repetitive failures continued to raise a red flag each time for variety of reasons. Drilling optimization in action was then introduced with its’ comprehensive drilling optimization package, where all historical norms, failures, lessons, and designs were analyzed thoroughly. New objectives and revised designs were proposed accompanied with a whole new process that ensured success. From challenges achieving required performance levels and dog legs in the top sections with increased risks of axial and lateral vibrations, to the difficulties faced in the landing section drilling through unconsolidated and reactive shales in the north, and through fragile weak formations in the south to the difficulties transferring weight to the bit at deeper depths in the horizontal laterals drilling highly porous zones of sticky limestones. Drilling optimization in action project was successfully introduced and executed with a renovated set of drilling parameters envelopes, revised trajectory designs, re-engineered BHA designs, right choice of fit for purpose bits models, adequate technology utilization and effective real-time performance reporting and monitoring. While cost optimization was the trend during the downturn, there was no better option to achieve desired financial results for both operator and service provider than the inclusion of the drilling optimization in action initiative into every well drilling program, it was proven to be an ultimate win-win technical and business solution.
{"title":"Drilling Optimization in Action - Delivering 125 Field Records in 6 Quarters","authors":"Ahmed El Hawy, Adil Al Busaidi, R. Bautista, M. Awadallah, M. R. Heidari, K. Saidi, Barton Escamilla, Zahra Al Abri, Guy deBoehmler, S. Harthi, Patrick A C M Haeser, Khaleel Al Riyami, Mahesh S. Picha","doi":"10.2118/192791-MS","DOIUrl":"https://doi.org/10.2118/192791-MS","url":null,"abstract":"As one of the worst oil & gas business downturns struck, the need for a revolutionary approach of drilling was needed. Optimization was the key word during that period, it was about time to look back at drilling fundamentals, review and learn from previous failures and lessons while establishing new foundation for a transformed yet successful process that ensured an all-time historical success. While many trials of drilling optimization initiatives were executed over the years, inconsistent drilling performance delivery and repetitive failures continued to raise a red flag each time for variety of reasons. Drilling optimization in action was then introduced with its’ comprehensive drilling optimization package, where all historical norms, failures, lessons, and designs were analyzed thoroughly. New objectives and revised designs were proposed accompanied with a whole new process that ensured success. From challenges achieving required performance levels and dog legs in the top sections with increased risks of axial and lateral vibrations, to the difficulties faced in the landing section drilling through unconsolidated and reactive shales in the north, and through fragile weak formations in the south to the difficulties transferring weight to the bit at deeper depths in the horizontal laterals drilling highly porous zones of sticky limestones. Drilling optimization in action project was successfully introduced and executed with a renovated set of drilling parameters envelopes, revised trajectory designs, re-engineered BHA designs, right choice of fit for purpose bits models, adequate technology utilization and effective real-time performance reporting and monitoring. While cost optimization was the trend during the downturn, there was no better option to achieve desired financial results for both operator and service provider than the inclusion of the drilling optimization in action initiative into every well drilling program, it was proven to be an ultimate win-win technical and business solution.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72659709","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. Salahuddin, Jamila M. Al Seiari, Abdulla S. Al Shehhi, K. Hammadi
The distribution of reservoir quality in tight carbonates depends primarily upon how diagenetic processes have modified the rock microstructure, leading to significant heterogeneity and anisotropy. The size and connectivity of the pore network may be enhanced by dissolution or reduced by cementation and compaction. Consequently, a clear understanding of the diagenetic process that responsible for the reservoir tightness would offer vital assurance on the spatial property distribution and future field development plan. In this paper, we have examined the factors which affect the distribution of porosity, permeability and reservoir quality in the Thamama Group, which is a prospective low permeability carbonate reservoir rock in Onshore Abu Dhabi. The dataset includes regional stratigraphy, well logs and core material from a number of wells, a suite of laboratory petrophysical measurements, seismic attributes, geomechanics, fracture study, and production history. Dataset analysis and interpretation suggested that the reservoir was deposited in shallow to deep marine low energy environment which led to deposition of fine to very fine grains (lime-mud supported) types of sediments. This, in turn, would produce poor reservoirs during compaction and finally leads to tightness. Because of the low permeability nature of this tight reservoir, it is quite challenging to obtain their complete reservoir properties and dynamic behavior. As in many other tight reservoir projects, a considerable area of the reservoir must be effectively stimulated during the hydraulic fracturing process to achieve economic productivity. In addition, development of tight reservoirs often faces challenges, for example, low initial production rates and high declining rate. This paper aims to frame all possible optimum development practices for tight reservoir in the studied field that should be considered for future development plan. We also investigated the application of new technology to enhance the poor oil recovery within the pool including horizontal drilling and multi-stage fracture completion technology. Furthermore, this paper also discusses well orientation relative to the far field principal stresses, hydraulic fractures treatment, fracture fluid selection, and nano-technology application. This, in turn, would provide valuable information on how to optimally develop this previously considered marginal and uneconomic reservoir.
{"title":"Tight Reservoir: Characterization, Modeling, and Development Feasibility","authors":"A. Salahuddin, Jamila M. Al Seiari, Abdulla S. Al Shehhi, K. Hammadi","doi":"10.2118/192778-MS","DOIUrl":"https://doi.org/10.2118/192778-MS","url":null,"abstract":"\u0000 The distribution of reservoir quality in tight carbonates depends primarily upon how diagenetic processes have modified the rock microstructure, leading to significant heterogeneity and anisotropy. The size and connectivity of the pore network may be enhanced by dissolution or reduced by cementation and compaction. Consequently, a clear understanding of the diagenetic process that responsible for the reservoir tightness would offer vital assurance on the spatial property distribution and future field development plan. In this paper, we have examined the factors which affect the distribution of porosity, permeability and reservoir quality in the Thamama Group, which is a prospective low permeability carbonate reservoir rock in Onshore Abu Dhabi.\u0000 The dataset includes regional stratigraphy, well logs and core material from a number of wells, a suite of laboratory petrophysical measurements, seismic attributes, geomechanics, fracture study, and production history. Dataset analysis and interpretation suggested that the reservoir was deposited in shallow to deep marine low energy environment which led to deposition of fine to very fine grains (lime-mud supported) types of sediments. This, in turn, would produce poor reservoirs during compaction and finally leads to tightness.\u0000 Because of the low permeability nature of this tight reservoir, it is quite challenging to obtain their complete reservoir properties and dynamic behavior. As in many other tight reservoir projects, a considerable area of the reservoir must be effectively stimulated during the hydraulic fracturing process to achieve economic productivity. In addition, development of tight reservoirs often faces challenges, for example, low initial production rates and high declining rate.\u0000 This paper aims to frame all possible optimum development practices for tight reservoir in the studied field that should be considered for future development plan. We also investigated the application of new technology to enhance the poor oil recovery within the pool including horizontal drilling and multi-stage fracture completion technology. Furthermore, this paper also discusses well orientation relative to the far field principal stresses, hydraulic fractures treatment, fracture fluid selection, and nano-technology application. This, in turn, would provide valuable information on how to optimally develop this previously considered marginal and uneconomic reservoir.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72689700","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}
Distributed temperature sensing (DTS) data interpretation has been extensively used in the last 10 years for improving acid placement for matrix acidizing operations. The DTS data are used for injection profiling during or after the acid and diverter are pumped into the reservoir. This study proposes an improved treatment schedule option for optimizing matrix stimulation operations with coiled tubing. In addition to the well-established DTS flow-profiling model, the capabilities of the new model include wormhole modeling, acid placement, and skin calculations. Coiled tubing-enabled optical fiber systems are usually used for improving the acid placement during or after matrix acidizing operations. A new model is proposed for designing and optimizing the matrix acidizing treatments in carbonate formations before, during, or after those operations. Specifically, this matrix acidizing model can be used in the pre-planning stimulation stage, before the DTS data is acquired, or during the stimulation, together with or separately from the DTS data. The model can be used in horizontal, deviated, and vertical wells with open-hole or perforated completions. The model takes into account the reservoir data (i.e., permeability, porosity, skin, pressure, and temperature), well data (i.e., tubing and casing sizes, length, number of perforations, etc.), and pumping schedule. Based on the input data and the wellbore hydraulic model, the output consists of the distributed acid rate and volume, wormhole length, and skin factor reduction. The DTS data from a synthetic matrix acidizing operation similar to one performed in an offshore carbonate field is used to validate the new model. An analysis of the results obtained for the previous and improved models is included, identifying the factors affecting the validation. Understanding these factors is crucial, because the new matrix acidizing model has the potential for use in the pre-planning stage with an enhanced acid placement schedule and can reduce operational costs by not using an optical fiber during the stimulation. In addition, the matrix acidizing model can be used during the matrix acidizing operations and can significantly reduce the acquisition time for the DTS data.
{"title":"Improved Acid Placement Modeling for Matrix Acidizing Optimization","authors":"S. Livescu, Andrea Vissotski, S. Chaudhary","doi":"10.2118/193119-MS","DOIUrl":"https://doi.org/10.2118/193119-MS","url":null,"abstract":"\u0000 Distributed temperature sensing (DTS) data interpretation has been extensively used in the last 10 years for improving acid placement for matrix acidizing operations. The DTS data are used for injection profiling during or after the acid and diverter are pumped into the reservoir. This study proposes an improved treatment schedule option for optimizing matrix stimulation operations with coiled tubing. In addition to the well-established DTS flow-profiling model, the capabilities of the new model include wormhole modeling, acid placement, and skin calculations.\u0000 Coiled tubing-enabled optical fiber systems are usually used for improving the acid placement during or after matrix acidizing operations. A new model is proposed for designing and optimizing the matrix acidizing treatments in carbonate formations before, during, or after those operations. Specifically, this matrix acidizing model can be used in the pre-planning stimulation stage, before the DTS data is acquired, or during the stimulation, together with or separately from the DTS data. The model can be used in horizontal, deviated, and vertical wells with open-hole or perforated completions. The model takes into account the reservoir data (i.e., permeability, porosity, skin, pressure, and temperature), well data (i.e., tubing and casing sizes, length, number of perforations, etc.), and pumping schedule. Based on the input data and the wellbore hydraulic model, the output consists of the distributed acid rate and volume, wormhole length, and skin factor reduction.\u0000 The DTS data from a synthetic matrix acidizing operation similar to one performed in an offshore carbonate field is used to validate the new model. An analysis of the results obtained for the previous and improved models is included, identifying the factors affecting the validation. Understanding these factors is crucial, because the new matrix acidizing model has the potential for use in the pre-planning stage with an enhanced acid placement schedule and can reduce operational costs by not using an optical fiber during the stimulation. In addition, the matrix acidizing model can be used during the matrix acidizing operations and can significantly reduce the acquisition time for the DTS data.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73827374","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}
Conformance improvement for ultra-high-temperature (130 °C) reservoirs is challenging due to the poor thermostability of conventional preformed particle gel (CPPG). To overcome the defect of thermal degradation, a novel hydrostable PPG (HT-PPG) was developed using the high-temperature tolerant crosslinker. In this work, a comparative study between the HT-PPG and CPPG has been presented in respects of their swelling behaviors, rheology properties and thermal stabilities. Particle swelling behaviors and viscoelasticities were firstly assessed in ambient. Using the swollen particles, a long-term aging at 130 °C underwent during which the physical status was monitored through high pressure vials (HPV). Furthermore, characterizations involved Scanning Electron Microscope (SEM) and Fourier Transform-Infrared Spectroscopy (FT-IR) were performed for both virgin and aged specimen. Thereby, an observation of gel microstructures and elucidation upon bonds or functional groups were provided. In addition to aging tests, we deployed the Differential Scanning Calorimetry (DSC) to investigate the inflection temperature as another indicator of particle thermostability. Attributed to the hydrostable crosslinker, the HT-PPG withstood 130 °C for at least 90 d. It was found that the HT-PPG effectively maintained its particulate shape, whereas, the CPPG completely degraded after 3-d aging. The HT-PPG maintained 28.8% of its initial storage modulus (G′). On the contrary, the normalized elasticity (G′/G0‘) of CPPG was only 0.43%. The SEM morphologies illustrated HT-PPG kept its rigid microstructure even after 90-d aging, while indicated destruction within CPPG network. According to FT-IR characterization, the decomposition of pristine crosslinker, N,N′-Methylenebisacrylamide in CPPG may account for its instability. DSC measurements furtherly demonstrated the favorability of HT-PPG in which HT-PPG exhibited a higher inflection temperature of 133.1 °C, however, CPPG only had an inflection temperature of 127.7 °C. This work turned out the novel HT-PPG could withstand ultra-high-temperature (130 °C) for more than 90 d, maintaining its particulate shape and viscoelasticity. This a durable plugging agent was notably superior to the CPPG, offering a candidate material for the conformance improvement in ultra-high-temperature reservoirs.
{"title":"Conformance Improvement for Ultra-High-Temperature Reservoir: A Comparative Study between Hydrostable and Conventional Preformed Particle Gel","authors":"Yifu Long, Bowen Yu, Changqian Zhu","doi":"10.2118/192738-MS","DOIUrl":"https://doi.org/10.2118/192738-MS","url":null,"abstract":"\u0000 Conformance improvement for ultra-high-temperature (130 °C) reservoirs is challenging due to the poor thermostability of conventional preformed particle gel (CPPG). To overcome the defect of thermal degradation, a novel hydrostable PPG (HT-PPG) was developed using the high-temperature tolerant crosslinker. In this work, a comparative study between the HT-PPG and CPPG has been presented in respects of their swelling behaviors, rheology properties and thermal stabilities. Particle swelling behaviors and viscoelasticities were firstly assessed in ambient. Using the swollen particles, a long-term aging at 130 °C underwent during which the physical status was monitored through high pressure vials (HPV). Furthermore, characterizations involved Scanning Electron Microscope (SEM) and Fourier Transform-Infrared Spectroscopy (FT-IR) were performed for both virgin and aged specimen. Thereby, an observation of gel microstructures and elucidation upon bonds or functional groups were provided. In addition to aging tests, we deployed the Differential Scanning Calorimetry (DSC) to investigate the inflection temperature as another indicator of particle thermostability. Attributed to the hydrostable crosslinker, the HT-PPG withstood 130 °C for at least 90 d. It was found that the HT-PPG effectively maintained its particulate shape, whereas, the CPPG completely degraded after 3-d aging. The HT-PPG maintained 28.8% of its initial storage modulus (G′). On the contrary, the normalized elasticity (G′/G0‘) of CPPG was only 0.43%. The SEM morphologies illustrated HT-PPG kept its rigid microstructure even after 90-d aging, while indicated destruction within CPPG network. According to FT-IR characterization, the decomposition of pristine crosslinker, N,N′-Methylenebisacrylamide in CPPG may account for its instability. DSC measurements furtherly demonstrated the favorability of HT-PPG in which HT-PPG exhibited a higher inflection temperature of 133.1 °C, however, CPPG only had an inflection temperature of 127.7 °C. This work turned out the novel HT-PPG could withstand ultra-high-temperature (130 °C) for more than 90 d, maintaining its particulate shape and viscoelasticity. This a durable plugging agent was notably superior to the CPPG, offering a candidate material for the conformance improvement in ultra-high-temperature reservoirs.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87192249","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}
Assessment of the porosity - fluid system, while challenging, is important in source rock oil plays. This is due to the wide range of hydrocarbon weight fractions, from bitumen to light hydrocarbon encountered in the source rock, along with the presence of both, the organic and the inorganic porosity systems, simultaneously. In such a play, while comparing zones of similar total porosity and water saturation, intervals with a better fluid type and porosity system will contribute more to the flow than other zones. In this paper an approach to poro-fluid typing a source rock is presented through examples from a carbonate source rock case study from the Middle East. The following core measurements were acquired on two wells: 1. NMR T1-T2 measurements on as received, oil saturated and water saturated samples, 2. Retort measurements for effective and total porosity and saturation analysis 3. Solvent extraction saturations for quantifying total hydrocarbon saturation, and 4. Mercury Injection Capillary Pressure Analysis for estimating pore throat size distribution. TOC measurements were also acquired on all the samples. A classification technique called the Blind Source Separation analysis (BSS) is carried out on the combined dataset of NMR 2D maps and various classes are identified based on the typical signatures observed on the maps in different saturation states. The classes identified using BSS were correlated to other core measurements to assign a physical meaning to each class. Based on the results, three key poro-fluid groups are identified. These groups are bitumen hosted porosity, porosity in the organics, and inorganic hosted porosity. By integrating results from MICP and SEM, we identify the typical pore sizes observed in the above groups and recommend zones that will bet better contributors to flow. Finally, we tie the results back to the limited measurements available in the log domain to predict zones with better flow potential.
{"title":"New Approach to Fluid Typing Concepts in Tight Carbonate Source Rocks","authors":"S. Steiner, L. Mosse, I. Raina","doi":"10.2118/193249-MS","DOIUrl":"https://doi.org/10.2118/193249-MS","url":null,"abstract":"\u0000 Assessment of the porosity - fluid system, while challenging, is important in source rock oil plays. This is due to the wide range of hydrocarbon weight fractions, from bitumen to light hydrocarbon encountered in the source rock, along with the presence of both, the organic and the inorganic porosity systems, simultaneously. In such a play, while comparing zones of similar total porosity and water saturation, intervals with a better fluid type and porosity system will contribute more to the flow than other zones. In this paper an approach to poro-fluid typing a source rock is presented through examples from a carbonate source rock case study from the Middle East.\u0000 The following core measurements were acquired on two wells: 1. NMR T1-T2 measurements on as received, oil saturated and water saturated samples, 2. Retort measurements for effective and total porosity and saturation analysis 3. Solvent extraction saturations for quantifying total hydrocarbon saturation, and 4. Mercury Injection Capillary Pressure Analysis for estimating pore throat size distribution. TOC measurements were also acquired on all the samples. A classification technique called the Blind Source Separation analysis (BSS) is carried out on the combined dataset of NMR 2D maps and various classes are identified based on the typical signatures observed on the maps in different saturation states.\u0000 The classes identified using BSS were correlated to other core measurements to assign a physical meaning to each class. Based on the results, three key poro-fluid groups are identified. These groups are bitumen hosted porosity, porosity in the organics, and inorganic hosted porosity. By integrating results from MICP and SEM, we identify the typical pore sizes observed in the above groups and recommend zones that will bet better contributors to flow. Finally, we tie the results back to the limited measurements available in the log domain to predict zones with better flow potential.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85797869","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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