S. Pooniwala, Ataur R. Malik, AbdulMuqtadir Khan, V. Plyashkevich, A. Yudin
In stimulation application, currently available degradable fiber-laden viscoelastic self-diverting acids (FLVSDA) are limited to moderate reservoir temperatures due to the lack of fiber integrity and stability. The upper bound temperature for current fiber is limited by the rate of polymer hydrolysis, which results in inadequate stability and fast degradation in an aqueous environment. As reservoirs are being encountered with higher temperatures, there is an industry need to expand the technology application to higher temperature environment (up to 350°F) for enhanced diversion and leakoff control. A novel high-temperature degradable fiber (HTF) was developed with two distinct features. First, the modified polymer is used with a highly ordered structure, resulting in higher melting point and enhanced thermal and hydrolytic stability compared to contemporary mid-temperature fiber (MTF). Second, the morphology is crimped, which enables better material dispersion and plugging efficiency when designed with higher concentration. Comprehensive laboratory tests were conducted for degradation and stability comparison in neutral and acidic media to replicate real acid treatment conditions. Also, bridging tests in slot geometry were conducted to characterize the diversion efficiency of the fiber-laden slurries. Finally, the material was tested in fields with temperatures ranging from 290 to 330°F. Fiber integrity and stability differentiated the performance of HTF and MTF at temperatures higher than 275°F. The critical point of HTF performance was achieved after 6 hours of exposure at 290°F in 100% spent 15% HCl with a concentration of 175 lbm/1000 gal US, whereas MTF is stable for less than 2 hours under the same testing conditions. The HTF demonstrated similar enhanced diversion efficacy when tested in more antagonistic media such as 50% spent acid. Fiber mass loss is considered as a characteristic of fiber stability, and premature fiber degradation compromises diversion effectiveness. To confirm the correct fiber shape at the degradation point, scanning electron microscopy (SEM) was used, and HTF showed no change in original shape and diameter. Pressure response at bridging was used as an additional characteristic for relative comparison of bridging ability for different fibers in laboratory conditions. A total of eighteen-stage acid stimulation treatments were conducted in six HT horizontal and vertical wells in fracturing and matrix acidizing modes using 51 fiber-laden diverter pills where significantly boosted diversion was observed with novel morphology fiber. Consequently, up to 30% to 40% production enhancement was observed in the wells treated with HTF due to effective stimulation fluids diversion and stimulation across the entire net pay. The broad-spectrum of fit-for-purpose diverters plays a critical role in optimal treatment fluid distribution during acid stimulation treatments. Innovation in the material and morphology of the existing f
在增产应用中，由于纤维的完整性和稳定性不足，目前可用的可降解纤维负载粘弹性自转向酸(FLVSDA)仅限于中等储层温度。目前纤维的上限温度受到聚合物水解速率的限制，这导致纤维在水环境中的稳定性不足和快速降解。随着储层温度的升高，行业需要将该技术应用到更高的温度环境(高达350°F)，以增强导流和泄漏控制。研制了一种新型高温可降解纤维(HTF)，具有两个明显的特点。首先，与当代中温纤维(MTF)相比，改性聚合物具有高度有序的结构，因此熔点更高，热稳定性和水解稳定性增强。二是形态卷曲，设计浓度越高，材料分散性越好，堵塞效率越高。进行了综合实验室试验，比较了中性和酸性介质中的降解和稳定性，以复制真实的酸处理条件。此外，还进行了槽形桥接试验，以表征纤维填充浆料的导流效率。最后，该材料在290至330°F的温度范围内进行了测试。在高于275°F的温度下，HTF和MTF的纤维完整性和稳定性区分了其性能。HTF性能的临界点是在290°F、浓度为175 lbm/1000 gal US、100%消耗的15% HCl中暴露6小时后达到的，而MTF在相同的测试条件下稳定时间不到2小时。HTF在更多拮抗介质(如50%废酸)中也表现出类似的增强导流效果。光纤质量损失被认为是光纤稳定性的一个特征，过早的光纤降解会影响导流效果。为了确定降解点的正确纤维形状，使用扫描电子显微镜(SEM)， HTF的原始形状和直径没有变化。桥接时的压力响应被用作实验室条件下不同纤维桥接能力相对比较的附加特征。在压裂和基质酸化模式下，共对6口高温水平井和直井进行了18级酸化处理，使用了51粒含纤维的暂堵剂，观察到新型形态纤维显著提高了暂堵效果。因此，在HTF处理的井中，由于有效的增产流体转移和整个净产层的增产，产量提高了30%至40%。在酸增产过程中，广谱适合用途的暂堵剂在优化压裂液分布方面起着关键作用。现有纤维组合的材料和形态的创新增加了基本价值，通过改进转向和优化储层增产，使油井获得更高的产量。
{"title":"Novel Morphology Self-Degradable Fiber Enables Enhanced Stimulation Fluid Diversion in High-Temperature Carbonate Formations","authors":"S. Pooniwala, Ataur R. Malik, AbdulMuqtadir Khan, V. Plyashkevich, A. Yudin","doi":"10.2523/iptc-22205-ms","DOIUrl":"https://doi.org/10.2523/iptc-22205-ms","url":null,"abstract":"\u0000 In stimulation application, currently available degradable fiber-laden viscoelastic self-diverting acids (FLVSDA) are limited to moderate reservoir temperatures due to the lack of fiber integrity and stability. The upper bound temperature for current fiber is limited by the rate of polymer hydrolysis, which results in inadequate stability and fast degradation in an aqueous environment. As reservoirs are being encountered with higher temperatures, there is an industry need to expand the technology application to higher temperature environment (up to 350°F) for enhanced diversion and leakoff control.\u0000 A novel high-temperature degradable fiber (HTF) was developed with two distinct features. First, the modified polymer is used with a highly ordered structure, resulting in higher melting point and enhanced thermal and hydrolytic stability compared to contemporary mid-temperature fiber (MTF). Second, the morphology is crimped, which enables better material dispersion and plugging efficiency when designed with higher concentration. Comprehensive laboratory tests were conducted for degradation and stability comparison in neutral and acidic media to replicate real acid treatment conditions. Also, bridging tests in slot geometry were conducted to characterize the diversion efficiency of the fiber-laden slurries. Finally, the material was tested in fields with temperatures ranging from 290 to 330°F.\u0000 Fiber integrity and stability differentiated the performance of HTF and MTF at temperatures higher than 275°F. The critical point of HTF performance was achieved after 6 hours of exposure at 290°F in 100% spent 15% HCl with a concentration of 175 lbm/1000 gal US, whereas MTF is stable for less than 2 hours under the same testing conditions. The HTF demonstrated similar enhanced diversion efficacy when tested in more antagonistic media such as 50% spent acid. Fiber mass loss is considered as a characteristic of fiber stability, and premature fiber degradation compromises diversion effectiveness. To confirm the correct fiber shape at the degradation point, scanning electron microscopy (SEM) was used, and HTF showed no change in original shape and diameter. Pressure response at bridging was used as an additional characteristic for relative comparison of bridging ability for different fibers in laboratory conditions. A total of eighteen-stage acid stimulation treatments were conducted in six HT horizontal and vertical wells in fracturing and matrix acidizing modes using 51 fiber-laden diverter pills where significantly boosted diversion was observed with novel morphology fiber. Consequently, up to 30% to 40% production enhancement was observed in the wells treated with HTF due to effective stimulation fluids diversion and stimulation across the entire net pay.\u0000 The broad-spectrum of fit-for-purpose diverters plays a critical role in optimal treatment fluid distribution during acid stimulation treatments. Innovation in the material and morphology of the existing f","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81899534","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}
E. Haryanto, Shubham Mishra, Saltanat Yersaiyn, Javed Jasmeed Adam, I. Khattak
Reservoir management of a developed oil field with the goal of fulfilling field development requirements and objectives is a continuous challenging process. Over time, the production and injection control, along with pressure maintenance strategies, are refined to achieve not only maximum recovery but also the most capital-efficient field development. A reservoir sectorization philosophy, by dissecting the reservoir into smaller reservoir management subareas, is commonly adopted for a large oil field. The high granularity sectorization scheme is often preferred to achieve a harmonized recovery across the field. However, a high sectorization number in a relatively continuous and noncompartmentalized reservoir can lead to some surveillance and data allocation challenges when wells are crossing multiple sector boundaries. With these challenges, we established two key aspects of reservoir management: first is to assess a potentially lower number of sectorization, and second is to generate a well level production and injection guideline. These guidelines must fulfill both short-term production sustainability assurance and long-term field development requirements and objectives. In this paper we present an integrated workflow to establish a reservoir management guideline. We started by an analytical evaluation of the historical reservoir management and waterflooding practices. The identified area(s) of improvement from the analytical evaluation were incorporated into dynamic models for different sectorization schemes. The simulation outputs were thoroughly analyzed by a standardized criteria matrix where several parameters were cross referenced to select the optimal sectorization scheme to achieve an even pressure depletion, harmonized sweep, absence of water-cut disparity along with strong economic indicators. A data analytic process on a large pool of historical well production tests and a historical surveillance database was performed to derive different well-level production and injection constraints. Subsequently, output results from sensitivity analysis were evaluated to finalize a robust new operating guideline. In this paper we will highlight some lessons learned from a case study where a lower number of reservoir management sectors also provided a substantial added value. The benefits are more apparent with implementation of new well-level guidelines where well-level production, injection, artificial lift, and pressure guidelines are recommended for operational considerations. The workflow to establish or to revise a reservoir management strategy from this study helped to lay out the critical foundation for all the stakeholders involved in asset management. The reservoir management practice presented in this paper is useful to make informed decisions so that well-rounded recommendations are available for production sustainability assurance and long-term field production performance optimization. Other fields may also benefit from the res
{"title":"Best Practice to Establish a Reservoir Management Guideline and Operating Strategy Envelope for Improved Water Injection Strategy and Production Sustainability Assurance in a Continuous Reservoir","authors":"E. Haryanto, Shubham Mishra, Saltanat Yersaiyn, Javed Jasmeed Adam, I. Khattak","doi":"10.2523/iptc-22036-ms","DOIUrl":"https://doi.org/10.2523/iptc-22036-ms","url":null,"abstract":"\u0000 Reservoir management of a developed oil field with the goal of fulfilling field development requirements and objectives is a continuous challenging process. Over time, the production and injection control, along with pressure maintenance strategies, are refined to achieve not only maximum recovery but also the most capital-efficient field development.\u0000 A reservoir sectorization philosophy, by dissecting the reservoir into smaller reservoir management subareas, is commonly adopted for a large oil field. The high granularity sectorization scheme is often preferred to achieve a harmonized recovery across the field. However, a high sectorization number in a relatively continuous and noncompartmentalized reservoir can lead to some surveillance and data allocation challenges when wells are crossing multiple sector boundaries. With these challenges, we established two key aspects of reservoir management: first is to assess a potentially lower number of sectorization, and second is to generate a well level production and injection guideline. These guidelines must fulfill both short-term production sustainability assurance and long-term field development requirements and objectives.\u0000 In this paper we present an integrated workflow to establish a reservoir management guideline. We started by an analytical evaluation of the historical reservoir management and waterflooding practices. The identified area(s) of improvement from the analytical evaluation were incorporated into dynamic models for different sectorization schemes. The simulation outputs were thoroughly analyzed by a standardized criteria matrix where several parameters were cross referenced to select the optimal sectorization scheme to achieve an even pressure depletion, harmonized sweep, absence of water-cut disparity along with strong economic indicators. A data analytic process on a large pool of historical well production tests and a historical surveillance database was performed to derive different well-level production and injection constraints. Subsequently, output results from sensitivity analysis were evaluated to finalize a robust new operating guideline.\u0000 In this paper we will highlight some lessons learned from a case study where a lower number of reservoir management sectors also provided a substantial added value. The benefits are more apparent with implementation of new well-level guidelines where well-level production, injection, artificial lift, and pressure guidelines are recommended for operational considerations. The workflow to establish or to revise a reservoir management strategy from this study helped to lay out the critical foundation for all the stakeholders involved in asset management.\u0000 The reservoir management practice presented in this paper is useful to make informed decisions so that well-rounded recommendations are available for production sustainability assurance and long-term field production performance optimization. Other fields may also benefit from the res","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91402033","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}
Dispersion and attenuation analysis can be used to determine formation anisotropy induced by fractures, or stresses. In this paper, we propose a nonparametric spectrum estimation method to get phase dispersion characteristics and attenuation coefficient. By designing an appropriate vector filter, phase velocity, attenuation coefficient and amplitude can be inverted from the waveform recorded by the receiver array. Performance analysis of this algorithm is compared with EPM and FBMP, based on the analysis, the proposed method is capable of achieving high resolution and precision as the parametric spectrum estimation methods in the meantime, it also keeps high stability as the other nonparametric spectrum estimation methods. At last, applications to synthetic waveforms modeled using finite difference method show its efficiency.
{"title":"A Nonparametric Estimation Method for Acoustic Dispersion and Attenuation Analysis","authors":"B. Wang, Wei Li","doi":"10.2523/iptc-21948-ea","DOIUrl":"https://doi.org/10.2523/iptc-21948-ea","url":null,"abstract":"\u0000 Dispersion and attenuation analysis can be used to determine formation anisotropy induced by fractures, or stresses. In this paper, we propose a nonparametric spectrum estimation method to get phase dispersion characteristics and attenuation coefficient. By designing an appropriate vector filter, phase velocity, attenuation coefficient and amplitude can be inverted from the waveform recorded by the receiver array. Performance analysis of this algorithm is compared with EPM and FBMP, based on the analysis, the proposed method is capable of achieving high resolution and precision as the parametric spectrum estimation methods in the meantime, it also keeps high stability as the other nonparametric spectrum estimation methods. At last, applications to synthetic waveforms modeled using finite difference method show its efficiency.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79522168","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}
Mahmoud Hameed, M. Gouda, A. Abouzaid, M. Selim, Albaraa Alrushud
It is well known in the Oil & Gas industry that Rotary Steerable Systems (RSS) are the most utilized and important drilling technology to optimize the placement of highly deviated and horizontal wells thus maximizing exposure to target reservoirs. RSS benefits over conventional motorized directional drilling are simply summarized as delivering a smooth borehole trajectory via continual tight control of borehole inclination and azimuth without any interruption to the drilling process. A vital measurement of the RSS system is the Near Bit Inclination (NBI due to its proximity to the drilling bit, its continuous real-time updates and tight tolerance range of (0.01 – 0.15 deg.) when correlated to conventional Measurements While Drilling (MWD) directional surveys. This gives NBI measurements a higher credibility as it provides better visibility on the detailed borehole trajectory and this will lead to enhanced decision making while drilling, as compared to the official borehole trajectory which is currently being mapped based on conventional MWD surveys "static" stations which are only taken over fixed depth increments (≈ 95ft MD, or a drill pipe stand length). The use of NBI provides a significant improvement over current True Vertical Depth (TVD) calculations using these stationary borehole inclination and azimuth measurementswhich will not be responsive to any wellbore trajectory changes between adjacent survey stations and the final resultant borehole trajectory will be a series of interpolations between thesesurvey stations. This in turn will have a strong influence on real-time geological interpretations like Formations tops, Formation true dip and associated True Stratigraphic Thickness (TST), which leads at the end to inaccurate well placement through target reservoirs as well as inaccurate reserve estimates. Considering post-well Geological work; subsurface maps need accurate True Vertical Depth Subsea (TVDSS) calculations for the planning of future lateral wells placement, especially those targeting thin reservoirs, in which reservoir navigation is itself a challenge.This paper sheds light on the importance of having real-time TVD calculations based on continuous updates of real-time NBI and borehole azimuth, rather than sparse updates from stationary MWD surveys. It also presents a few examples of effects of borehole inclination changes between stationary MWD surveys, either planned or accidental, on the TVD calculations and on final well placement This paper is shedding the light on the importance of having Real-time TVD calculations based on continuous updates of Real-time NBI and borehole azimuth, rather than those updates from stationary MWD surveys. It is also presenting few examples about the effects of borehole inclination changes between stationary MWD surveys, either normal or accidental ones, on the TVD calculations and generally on the final well placement.
{"title":"Reducing the Uncertainties Associated with Unseen Borehole Inclination Changes between Directional Survey Stations on TVD Calculations and Post-Geological Interpretation","authors":"Mahmoud Hameed, M. Gouda, A. Abouzaid, M. Selim, Albaraa Alrushud","doi":"10.2523/iptc-22218-ea","DOIUrl":"https://doi.org/10.2523/iptc-22218-ea","url":null,"abstract":"\u0000 It is well known in the Oil & Gas industry that Rotary Steerable Systems (RSS) are the most utilized and important drilling technology to optimize the placement of highly deviated and horizontal wells thus maximizing exposure to target reservoirs. RSS benefits over conventional motorized directional drilling are simply summarized as delivering a smooth borehole trajectory via continual tight control of borehole inclination and azimuth without any interruption to the drilling process. A vital measurement of the RSS system is the Near Bit Inclination (NBI due to its proximity to the drilling bit, its continuous real-time updates and tight tolerance range of (0.01 – 0.15 deg.) when correlated to conventional Measurements While Drilling (MWD) directional surveys. This gives NBI measurements a higher credibility as it provides better visibility on the detailed borehole trajectory and this will lead to enhanced decision making while drilling, as compared to the official borehole trajectory which is currently being mapped based on conventional MWD surveys \"static\" stations which are only taken over fixed depth increments (≈ 95ft MD, or a drill pipe stand length). The use of NBI provides a significant improvement over current True Vertical Depth (TVD) calculations using these stationary borehole inclination and azimuth measurementswhich will not be responsive to any wellbore trajectory changes between adjacent survey stations and the final resultant borehole trajectory will be a series of interpolations between thesesurvey stations. This in turn will have a strong influence on real-time geological interpretations like Formations tops, Formation true dip and associated True Stratigraphic Thickness (TST), which leads at the end to inaccurate well placement through target reservoirs as well as inaccurate reserve estimates. Considering post-well Geological work; subsurface maps need accurate True Vertical Depth Subsea (TVDSS) calculations for the planning of future lateral wells placement, especially those targeting thin reservoirs, in which reservoir navigation is itself a challenge.This paper sheds light on the importance of having real-time TVD calculations based on continuous updates of real-time NBI and borehole azimuth, rather than sparse updates from stationary MWD surveys. It also presents a few examples of effects of borehole inclination changes between stationary MWD surveys, either planned or accidental, on the TVD calculations and on final well placement\u0000 This paper is shedding the light on the importance of having Real-time TVD calculations based on continuous updates of Real-time NBI and borehole azimuth, rather than those updates from stationary MWD surveys. It is also presenting few examples about the effects of borehole inclination changes between stationary MWD surveys, either normal or accidental ones, on the TVD calculations and generally on the final well placement.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82329014","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}
Maryam Alblushi, K. Nasser, Mohammad Readean, A. Ghamdi
Since the introduction of the first electrical resistivity well log by Marcel and Conrad Schlumberger in 1927, the field of petrophysical well logging experienced significant technological advancements [3]. One of the new technologies was Logging While Drilling (LWD), which allows for real time data streaming and acquisition from the initial drilling depth to the target depth. The target depth sometimes reaches more than 25,000 feet, resulting in wealth of captured data [7]. As special logging probes scan given subsurface intervals, a long list of diverse readings is collected as functions of either depth or time [4]. Unfortunately, most of the obtained data cannot be used as is; several processing, calibration and interpretation activities must be performed on the stored raw data to extract useful insights about the penetrated formations [5]. While these data processing activities are plausible for one particular hydrocarbon reservoir using conventional processing techniques, performing field-wide petrophysical studies can be a real challenge. However, big data technologies can be seen as a potential solution as petrophysical data satisfies the main characteristics of big data. Such characteristics include the high volume, velocity, extreme variety of measurement types and formats, and the uncertain veracity of data attained from several vendors and sensors. In this paper, we first review the major challenges limiting geoscientists, geophysicists and petroleum engineers from fully exploiting petrophysical data. Then, we propose a big data-based framework which can help overcome some of these challenges by capitalizing on advanced processing techniques. Finally, we discuss the results of applying the framework on a defined business case.
{"title":"Big Data Integration Framework for Processing Petrophysical Data","authors":"Maryam Alblushi, K. Nasser, Mohammad Readean, A. Ghamdi","doi":"10.2523/iptc-22170-ms","DOIUrl":"https://doi.org/10.2523/iptc-22170-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Since the introduction of the first electrical resistivity well log by Marcel and Conrad Schlumberger in 1927, the field of petrophysical well logging experienced significant technological advancements [3]. One of the new technologies was Logging While Drilling (LWD), which allows for real time data streaming and acquisition from the initial drilling depth to the target depth. The target depth sometimes reaches more than 25,000 feet, resulting in wealth of captured data [7]. As special logging probes scan given subsurface intervals, a long list of diverse readings is collected as functions of either depth or time [4]. Unfortunately, most of the obtained data cannot be used as is; several processing, calibration and interpretation activities must be performed on the stored raw data to extract useful insights about the penetrated formations [5].\u0000 While these data processing activities are plausible for one particular hydrocarbon reservoir using conventional processing techniques, performing field-wide petrophysical studies can be a real challenge. However, big data technologies can be seen as a potential solution as petrophysical data satisfies the main characteristics of big data. Such characteristics include the high volume, velocity, extreme variety of measurement types and formats, and the uncertain veracity of data attained from several vendors and sensors.\u0000 In this paper, we first review the major challenges limiting geoscientists, geophysicists and petroleum engineers from fully exploiting petrophysical data. Then, we propose a big data-based framework which can help overcome some of these challenges by capitalizing on advanced processing techniques. Finally, we discuss the results of applying the framework on a defined business case.\u0000","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82363416","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}
Flávia Koch Ferreira, J. Fiorotti, L. Brunherotto, Marcelo Cunha, J. L. Paredes, T. Piedade, Rafael Peralta, Geraldo Filho
Drilling time and resources for casing and cementing the wellbore represent a significant cost in oil well construction. Therefore, slender wells have been targeted to be constructed with less phases and higher efficiency reducing costs by half. The objective of this paper is to present how a fit-for-purpose foam cement system contributed to delivering a dependable barrier for a True-One-Trip Ultra-Slender well, where a single barrier shall provide wellbore mechanical integrity and competent isolation from the reservoir to seabed. The methodology for this foam cement job involved, initially, hydraulic and thermal modeling, followed by lab testing, such as thickening time, compressive strength, and foam stability tests. The pumping schedule included 4 different tailored systems that were pumped to maximize probability of returns at the mudline. By using the constant-nitrogen-rate technique, the foam quality was optimized to help ensure slurry and foam stability at downhole conditions. Proper energized fluid selection and casing centralization were placed to guarantee a slurry system application with improved mud removal capacity and optimized standoff to avoid slurry contamination attributed to channeling. During execution, no issues were observed until reaching the final depth. The open hole diameter was estimated based on volumetric determination by pumping a tracer and a scavenger slurry, to be visualized at the mudline. Based on that information, further volumes were fine tuned and pumped to ensure appropriated foam cement quality and density along the wellbore section. As one of the major objectives of the job, returns could be achieved at mudline and the final differential pressure was higher than expected, indicating a cement sheath in the annulus had extensive length. Cement job evaluation was performed after the job using sonic and ultrasonic tools to confirm the quality of the barrier placed in the annulus. Additionally, an advanced Cement Evaluation was executed and showed excellent isolation for the slurries placed in the well. The results from this unprecedented operation in Brazil have proven the features and benefits of using foamed cement in ultra-slender wells for specific challenges, such as: requirement of returns at mudline, application in long length zonal isolation operations, and the necessity of high-strength low-density solutions near the mudline. After this job, similar wells have been constructed in the same area, and the applied technique has continuously proven to be a dependable and sound solution for similar scenarios. Based on the successful case history presented in this paper, the application of foam cement technology in ultra-slender wells represent an innovative and dependable solution for the actual and future high-efficiency wellbore geometries. By reducing the risks of having a single cement sheath in the entire well, it enables the oilwell industry to reduce time and risks during wellbore construction an
{"title":"Tailored Dependable Barrier Enables Operator to Flawlessly Complete True One Trip Ultra Slender Deepwater Well","authors":"Flávia Koch Ferreira, J. Fiorotti, L. Brunherotto, Marcelo Cunha, J. L. Paredes, T. Piedade, Rafael Peralta, Geraldo Filho","doi":"10.2523/iptc-21977-ms","DOIUrl":"https://doi.org/10.2523/iptc-21977-ms","url":null,"abstract":"\u0000 Drilling time and resources for casing and cementing the wellbore represent a significant cost in oil well construction. Therefore, slender wells have been targeted to be constructed with less phases and higher efficiency reducing costs by half. The objective of this paper is to present how a fit-for-purpose foam cement system contributed to delivering a dependable barrier for a True-One-Trip Ultra-Slender well, where a single barrier shall provide wellbore mechanical integrity and competent isolation from the reservoir to seabed. The methodology for this foam cement job involved, initially, hydraulic and thermal modeling, followed by lab testing, such as thickening time, compressive strength, and foam stability tests. The pumping schedule included 4 different tailored systems that were pumped to maximize probability of returns at the mudline. By using the constant-nitrogen-rate technique, the foam quality was optimized to help ensure slurry and foam stability at downhole conditions. Proper energized fluid selection and casing centralization were placed to guarantee a slurry system application with improved mud removal capacity and optimized standoff to avoid slurry contamination attributed to channeling.\u0000 During execution, no issues were observed until reaching the final depth. The open hole diameter was estimated based on volumetric determination by pumping a tracer and a scavenger slurry, to be visualized at the mudline. Based on that information, further volumes were fine tuned and pumped to ensure appropriated foam cement quality and density along the wellbore section. As one of the major objectives of the job, returns could be achieved at mudline and the final differential pressure was higher than expected, indicating a cement sheath in the annulus had extensive length. Cement job evaluation was performed after the job using sonic and ultrasonic tools to confirm the quality of the barrier placed in the annulus. Additionally, an advanced Cement Evaluation was executed and showed excellent isolation for the slurries placed in the well. The results from this unprecedented operation in Brazil have proven the features and benefits of using foamed cement in ultra-slender wells for specific challenges, such as: requirement of returns at mudline, application in long length zonal isolation operations, and the necessity of high-strength low-density solutions near the mudline. After this job, similar wells have been constructed in the same area, and the applied technique has continuously proven to be a dependable and sound solution for similar scenarios.\u0000 Based on the successful case history presented in this paper, the application of foam cement technology in ultra-slender wells represent an innovative and dependable solution for the actual and future high-efficiency wellbore geometries. By reducing the risks of having a single cement sheath in the entire well, it enables the oilwell industry to reduce time and risks during wellbore construction an","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77965623","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}
During the first quarter of 2020, the world encountered a crucial and unprecedented health crisis. The global transmission of COVID-19 poses a significant challenging situation for Oil and Gas industry, particularly in the absence of standardized procedures and recognized methods. Like many other countries worldwide, Saudi Arabia implemented the lockdown for utmost public and private services and controlled population movement through curfew. With the execution of these tight mitigation requirements, Halliburton Saudi Arabia has been able to maintain business continuity by looking at the basic approach of health, safety, and environmental (HSE) processes through crisis management decision making and utilizing digital solutions. The purpose of this paper is to showcase how Halliburton Saudi Arabia developed sustainable adjustable process and methods that reduced exposure and the pandemic-related potential risks associated with working in offices, rig sites, workshops, and laboratories while maintaining business continuity in operation, manufacturing, and technology. Halliburton Saudi Arabia preformed risk analysis, tracking systems, exposure modification methodologies, communication strategies and management decisions that helped the company overcome challenges during the pandemic. The implementation of risk assessments, adaptable safety procedures and utilizing more than 5 digital platforms, served Halliburton employees and its work force throughout 2021 and into 2032. In this paper, we share lessons learned during the pandemic, how we overcame the unprecedented health crisis and how we continue to deal with the pandemic impact.
{"title":"Halliburton Saudi Arabia Crisis Management and Lessons Learn During COVID-19 Pandemic in the Kingdom of Saudi Arabia","authors":"Roa'a Albish, Fahad A. Al-Qarni, Khalid Al-Zaidy","doi":"10.2523/iptc-22140-ea","DOIUrl":"https://doi.org/10.2523/iptc-22140-ea","url":null,"abstract":"\u0000 During the first quarter of 2020, the world encountered a crucial and unprecedented health crisis. The global transmission of COVID-19 poses a significant challenging situation for Oil and Gas industry, particularly in the absence of standardized procedures and recognized methods. Like many other countries worldwide, Saudi Arabia implemented the lockdown for utmost public and private services and controlled population movement through curfew. With the execution of these tight mitigation requirements, Halliburton Saudi Arabia has been able to maintain business continuity by looking at the basic approach of health, safety, and environmental (HSE) processes through crisis management decision making and utilizing digital solutions.\u0000 The purpose of this paper is to showcase how Halliburton Saudi Arabia developed sustainable adjustable process and methods that reduced exposure and the pandemic-related potential risks associated with working in offices, rig sites, workshops, and laboratories while maintaining business continuity in operation, manufacturing, and technology.\u0000 Halliburton Saudi Arabia preformed risk analysis, tracking systems, exposure modification methodologies, communication strategies and management decisions that helped the company overcome challenges during the pandemic.\u0000 The implementation of risk assessments, adaptable safety procedures and utilizing more than 5 digital platforms, served Halliburton employees and its work force throughout 2021 and into 2032. In this paper, we share lessons learned during the pandemic, how we overcame the unprecedented health crisis and how we continue to deal with the pandemic impact.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76062850","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 conventional oil drilling process includes the drilling of a well, a reservoir having pressure and a mixture of oil/gas/water flowing out of the ground. Eventually as a well gets older and the reservoir pressured reduces, some form of artificial lift becomes necessary. For wells producing a significant amount of gas, either gas lift or a related method (plunger lift for example) tends to be the sensible solution. Ultimately, once the reservoir pressure and production levels have depleted substantially, rod pumping becomes relevant. Each production method requires a specific surface piping and valving arrangement to allow for the wellbore fluids to flow with minimum restriction as well as fluid injection as applicable. Following safety and operational protocols established by each operator, the surface arrangement should be inclusive of multiple barriers to shut down production should the need arise. Redundancy becomes a necessity to ensure compliance with safety regulations while protecting the assets. Adapting the wellhead stack to the production method requires major interventions with the associated cost and deferred production. Logistic and planning can be critical for smooth modification of the wellhead stack especially when several wells are involved. In this context, a universal piece of equipment engineered for compatibility with all production stages of the well can add value to the operation by eliminating wellhead stack modifications and minimizing deferred production through the well life cycle.
{"title":"Multi-Purpose Wellhead","authors":"J. Garcia","doi":"10.2523/iptc-22458-ea","DOIUrl":"https://doi.org/10.2523/iptc-22458-ea","url":null,"abstract":"\u0000 The conventional oil drilling process includes the drilling of a well, a reservoir having pressure and a mixture of oil/gas/water flowing out of the ground. Eventually as a well gets older and the reservoir pressured reduces, some form of artificial lift becomes necessary. For wells producing a significant amount of gas, either gas lift or a related method (plunger lift for example) tends to be the sensible solution. Ultimately, once the reservoir pressure and production levels have depleted substantially, rod pumping becomes relevant.\u0000 Each production method requires a specific surface piping and valving arrangement to allow for the wellbore fluids to flow with minimum restriction as well as fluid injection as applicable. Following safety and operational protocols established by each operator, the surface arrangement should be inclusive of multiple barriers to shut down production should the need arise. Redundancy becomes a necessity to ensure compliance with safety regulations while protecting the assets.\u0000 Adapting the wellhead stack to the production method requires major interventions with the associated cost and deferred production. Logistic and planning can be critical for smooth modification of the wellhead stack especially when several wells are involved.\u0000 In this context, a universal piece of equipment engineered for compatibility with all production stages of the well can add value to the operation by eliminating wellhead stack modifications and minimizing deferred production through the well life cycle.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74254685","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. Hussain, A. Amao, K. Al-Ramadan, L. Babalola, H. Kesserwan
X-ray fluorescence (XRF) is one of the most preferred method preferent methods for elemental analysis and the recent rapid development in spectroscopy has ushered in new ways to look at data generated by most XRF setups beyond the current conventional usage. We hypothesized that particle size and morphology of rock samples can influence fluorescence spectra acquisition. Such interference if analyzed, can unravel new usage for XRF spectra. In this study, we propose the use of raw XRF spectra data for the determination of grain size by superimposition and multiple spectra-cross plots technique. The other known methods of measuring grain size (GS) depending on whether samples are loose or consolidated, include laser granulometry, sieve, and image analyses. Most of these methods have known limitations in their application on an intact rock. The proposed method is designed to address these individual challenges.
{"title":"A Novel Method to Obtain Grain Size Distributions of Intact Rock Samples Using X-Ray Fluorescence Spectra","authors":"M. Hussain, A. Amao, K. Al-Ramadan, L. Babalola, H. Kesserwan","doi":"10.2523/iptc-21876-ea","DOIUrl":"https://doi.org/10.2523/iptc-21876-ea","url":null,"abstract":"\u0000 X-ray fluorescence (XRF) is one of the most preferred method preferent methods for elemental analysis and the recent rapid development in spectroscopy has ushered in new ways to look at data generated by most XRF setups beyond the current conventional usage. We hypothesized that particle size and morphology of rock samples can influence fluorescence spectra acquisition. Such interference if analyzed, can unravel new usage for XRF spectra. In this study, we propose the use of raw XRF spectra data for the determination of grain size by superimposition and multiple spectra-cross plots technique. The other known methods of measuring grain size (GS) depending on whether samples are loose or consolidated, include laser granulometry, sieve, and image analyses. Most of these methods have known limitations in their application on an intact rock. The proposed method is designed to address these individual challenges.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78793313","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. M. Algaiar, Hichem Horra, Moustafa Farhat, Ragab Tolba, Mohamed Benzeghiba
Great efforts are invested in improving oil and gas reservoir recovery to meet the rise in local energy consumption and global demand. To improve the production and ultimate recovery of a major oil field in the Middle East, extended-reach drilling (ERD) is executed in wells with long horizontal multilaterals to achieve maximum reservoir contact (MRC), the increase in ERD wells demand led to many drilling challenges and difficulties. The challenges in designing ERD wells are multiple, such as trajectory control, well collision avoidance, hole cleaning efficiency, high torque & drag, differential sticking, wellbore stability, Logging-while-drilling (LWD) log quality and long circulating hours. In recognition of this, the dedicated operator and service team developed a drilling optimization roadmap that addresses the drilling challenges at the greatest performance impact. The optimization roadmap comprises enhanced trajectory design, drillstring design, drilling fluids and system hydraulics design, and subsurface geomechanical modelling in the planning phase, in addition to realtime formation evaluation, hole cleaning and torque and drag monitoring, and drillstring vibrations management in the execution phase. The exploitation of 4 inch and 5 inch tapered drillstring as opposed to complete 5 inch drillstring for drilling torque reduction and its related tripping behavior was explored on the first Optimization stage of the optimization plan, using this approach successfully reduced drilling torque, but the tripability out of hole became problematic and more difficult. The first stage outcome called for utilizing complete 5 inch drillpipe string in addition to oil-based mud (OBM) lubricant (OMNI-LUBETM) that resulted in 20-25% reduction of the drilling torque. Tripability improved compared to 4 inch drill pipe in the second optimization stage, but still facing some issues in few laterals. On the final optimization stage, the engineering & operations team introduced the Dog Leg Reamer tool on top of the drilling bottomhole assembly (BHA) which resulted in a significant improvement in the tripping behavior in addition to a smoother hookload along in the drilled interval. The implementation of the holistic drilling system design and optimization methodologies helped achieving new performance records, lateral after lateral. The optimization roadmap delivered a proven performance in the most challenging drilling environments. The key technical challenges, performance optimization roadmap, job execution, and post well evaluation of the drilling performance are presented in this paper.
{"title":"Successful Optimization Roadmap Enhanced the Drilling Performance in the 8.5 Inch Lateral Sections of Extended Reach Multilateral Wells","authors":"M. M. Algaiar, Hichem Horra, Moustafa Farhat, Ragab Tolba, Mohamed Benzeghiba","doi":"10.2523/iptc-21987-ms","DOIUrl":"https://doi.org/10.2523/iptc-21987-ms","url":null,"abstract":"\u0000 Great efforts are invested in improving oil and gas reservoir recovery to meet the rise in local energy consumption and global demand. To improve the production and ultimate recovery of a major oil field in the Middle East, extended-reach drilling (ERD) is executed in wells with long horizontal multilaterals to achieve maximum reservoir contact (MRC), the increase in ERD wells demand led to many drilling challenges and difficulties.\u0000 The challenges in designing ERD wells are multiple, such as trajectory control, well collision avoidance, hole cleaning efficiency, high torque & drag, differential sticking, wellbore stability, Logging-while-drilling (LWD) log quality and long circulating hours. In recognition of this, the dedicated operator and service team developed a drilling optimization roadmap that addresses the drilling challenges at the greatest performance impact. The optimization roadmap comprises enhanced trajectory design, drillstring design, drilling fluids and system hydraulics design, and subsurface geomechanical modelling in the planning phase, in addition to realtime formation evaluation, hole cleaning and torque and drag monitoring, and drillstring vibrations management in the execution phase.\u0000 The exploitation of 4 inch and 5 inch tapered drillstring as opposed to complete 5 inch drillstring for drilling torque reduction and its related tripping behavior was explored on the first Optimization stage of the optimization plan, using this approach successfully reduced drilling torque, but the tripability out of hole became problematic and more difficult. The first stage outcome called for utilizing complete 5 inch drillpipe string in addition to oil-based mud (OBM) lubricant (OMNI-LUBETM) that resulted in 20-25% reduction of the drilling torque. Tripability improved compared to 4 inch drill pipe in the second optimization stage, but still facing some issues in few laterals. On the final optimization stage, the engineering & operations team introduced the Dog Leg Reamer tool on top of the drilling bottomhole assembly (BHA) which resulted in a significant improvement in the tripping behavior in addition to a smoother hookload along in the drilled interval. The implementation of the holistic drilling system design and optimization methodologies helped achieving new performance records, lateral after lateral. The optimization roadmap delivered a proven performance in the most challenging drilling environments.\u0000 The key technical challenges, performance optimization roadmap, job execution, and post well evaluation of the drilling performance are presented in this paper.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78882446","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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