Yingcheng Li, Bailing Kong, Weidong Zhang, X. Bao, J. Jin, Xinyue Wu, Yanhua Liu, Yanxia Wang, Xiujuan He, Hui Zhang, Z. Shen, O. Sha, Weimin Yang
Cationic surfactant is never used in Enhanced Oil Recovery (EOR) for negative charged sandstone reservoirs because of high adsorption. Since January 2012, the first field scale application of alkaline surfactant polymer (ASP) flood in the world with thermal stable, highly efficient mixtures of anionic- cationic surfactants (S) for super low acid oils, was carried out in Sinopec for a high water cut mature sandstone reservoir with approximately 8,000 mg/L total dissolved solids (TDS), temperature of 81°C, to demonstrate the potential of this novel surfactants to recover residual oil from as high as 53.3% recovery percent of reserves. The maximal water cut decreased from 97.9% to 90.2%, along with peak daily oil production increased from 23.0 t to 106.1 t. The cumulative incremental oil by ASP flood at the end of December 2018 is about 276.1 kt and the oil recovery was increased by 10.65% OOIP. The estimated ultimate oil recovery can be increased by 14.2% OOIP and yield up to 67.5% OOIP.
{"title":"ASP Flood With Novel Mixtures of Anionic-Cationic Surfactants for High Water Cut Mature Sandstone Reservoir: From Laboratory to Field Application","authors":"Yingcheng Li, Bailing Kong, Weidong Zhang, X. Bao, J. Jin, Xinyue Wu, Yanhua Liu, Yanxia Wang, Xiujuan He, Hui Zhang, Z. Shen, O. Sha, Weimin Yang","doi":"10.2118/195056-MS","DOIUrl":"https://doi.org/10.2118/195056-MS","url":null,"abstract":"\u0000 Cationic surfactant is never used in Enhanced Oil Recovery (EOR) for negative charged sandstone reservoirs because of high adsorption. Since January 2012, the first field scale application of alkaline surfactant polymer (ASP) flood in the world with thermal stable, highly efficient mixtures of anionic- cationic surfactants (S) for super low acid oils, was carried out in Sinopec for a high water cut mature sandstone reservoir with approximately 8,000 mg/L total dissolved solids (TDS), temperature of 81°C, to demonstrate the potential of this novel surfactants to recover residual oil from as high as 53.3% recovery percent of reserves. The maximal water cut decreased from 97.9% to 90.2%, along with peak daily oil production increased from 23.0 t to 106.1 t. The cumulative incremental oil by ASP flood at the end of December 2018 is about 276.1 kt and the oil recovery was increased by 10.65% OOIP. The estimated ultimate oil recovery can be increased by 14.2% OOIP and yield up to 67.5% OOIP.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76230005","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. Abahussain, Rafael Pino, Ajay Addagalla, Anas Qadi
Investing in new wells during a period of volatile oil prices is not the best option for E&P companies. During hard economic environments such companies make plans to produce or enhance hydrocarbon recovery from existing wells for continuous cash flow and to maximize rate of return on investors’ expectations. In several regions, it may take years to produce the hydrocarbons from the drilled well. These wells were drilled and completed successfully, but they were idle, waiting for the production commencement date. This delay depends on various factors including reservoir conditions, market conditions and geopolitical situations. Due to these delays, wells undergo severe formation damage that either minimizes hydrocarbon production or halts hydrocarbon flow completely. A solution was identified to increase production from a damaged well or bring a non-producing well back into production. This solution is based on microemulsion chemistry. Microemulsions consist of mixtures of oil and water, along with surfactants and other components. These fluids are optically transparent, thermodynamically stable, possess extremely low interfacial tension, and require minimum or zero energy to form. Microemulsions are transparent because of an extremely small droplet size. These are naturally occurring and have less risk involved in deploying and executing the job when compared to conventional solvent treatments. Cleaning efficiency and reaction time of microemulsions depend on many parameters including reservoir conditions, salinity, temperature and type of hydrocarbon used during the drilling or completion phase. These microemulsion fluids were pumped using an inflatable straddle packer (ISP) designed to isolate and divert into the required small area of exposure. The system consists of two inflatable packers with variable spaceout possibilities, enabling adequate positioning over the selective formation area. This tool was deployed using coiled tubing and real-time depth correlation to estimate the correct treatment zones. A customized fluid was designed using specialized surfactants, brine and an acid. These individual components were mixed on the surface and pumped down hole. This blend works by solubilizing oil and emulsifiers from the oil-based filter cake and forming a microemulsion. This paper discusses an openhole completion well that was drilled and then completed with ICD screens. Oil-based mud was left in the hole, causing severe damage that prevented bringing the well back to production. The designed surfactant package was pumped through an ISP tool that was suitable for the reservoir conditions. The ISP tool elastomers were designed after performing detailed lab tests that included the filter-cake destruction test, a wettability test and elastomer compatibility tests. Surfactant was pumped into the reservoir with an engineering approach, and successful results were achieved with good production results.
{"title":"Bringing Back the Damaged Wells into Production Using Microemulsion Technology","authors":"A. Abahussain, Rafael Pino, Ajay Addagalla, Anas Qadi","doi":"10.2118/194838-MS","DOIUrl":"https://doi.org/10.2118/194838-MS","url":null,"abstract":"\u0000 Investing in new wells during a period of volatile oil prices is not the best option for E&P companies. During hard economic environments such companies make plans to produce or enhance hydrocarbon recovery from existing wells for continuous cash flow and to maximize rate of return on investors’ expectations. In several regions, it may take years to produce the hydrocarbons from the drilled well. These wells were drilled and completed successfully, but they were idle, waiting for the production commencement date. This delay depends on various factors including reservoir conditions, market conditions and geopolitical situations. Due to these delays, wells undergo severe formation damage that either minimizes hydrocarbon production or halts hydrocarbon flow completely.\u0000 A solution was identified to increase production from a damaged well or bring a non-producing well back into production. This solution is based on microemulsion chemistry. Microemulsions consist of mixtures of oil and water, along with surfactants and other components. These fluids are optically transparent, thermodynamically stable, possess extremely low interfacial tension, and require minimum or zero energy to form. Microemulsions are transparent because of an extremely small droplet size. These are naturally occurring and have less risk involved in deploying and executing the job when compared to conventional solvent treatments. Cleaning efficiency and reaction time of microemulsions depend on many parameters including reservoir conditions, salinity, temperature and type of hydrocarbon used during the drilling or completion phase. These microemulsion fluids were pumped using an inflatable straddle packer (ISP) designed to isolate and divert into the required small area of exposure. The system consists of two inflatable packers with variable spaceout possibilities, enabling adequate positioning over the selective formation area. This tool was deployed using coiled tubing and real-time depth correlation to estimate the correct treatment zones.\u0000 A customized fluid was designed using specialized surfactants, brine and an acid. These individual components were mixed on the surface and pumped down hole. This blend works by solubilizing oil and emulsifiers from the oil-based filter cake and forming a microemulsion.\u0000 This paper discusses an openhole completion well that was drilled and then completed with ICD screens. Oil-based mud was left in the hole, causing severe damage that prevented bringing the well back to production. The designed surfactant package was pumped through an ISP tool that was suitable for the reservoir conditions. The ISP tool elastomers were designed after performing detailed lab tests that included the filter-cake destruction test, a wettability test and elastomer compatibility tests. Surfactant was pumped into the reservoir with an engineering approach, and successful results were achieved with good production results.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76496448","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 Cliff Head is one of the most significant discoveries in the offshore Northern Perth Basin. Hence, understanding the structure and geology of the field is essential to further evaluate the offshore region in the basin. Two structural models were developed with the objective to achieve a better understanding of this field. The first model is focused on the Permian and older strata, while the second model is for the overburden. In addition, reservoir properties models (e.g. porosity model and water saturation model) were developed to better understand the reservoir facies and hydrocarbon distribution. Examination of the structural models has shown that there are two main sets of faults within the Cliff Head area, which can be categorized into the following: the deep Permian faults that are truncated against the Late Permian unconformity, and younger Cretaceous faults that were developed during the Early Cretaceous rifting. It has also shown that the oil accumulation within the field is structurally trapped within Permian aged set of horsts and is mainly reservoired within the Irwin River Coal Measures. The secondary target (e.g. the underlying High Cliff Sandstone) is mostly beneath the regional oil-water contact of −1257.8 m TVDss, except in the highest structural point in the field, where Cliff Head-6 was drilled. The Irwin River Coal Measures in the study area contained four high resolution depositional sequences that displayed a finingupward pattern as depicted by the Gamma Ray log response and are interpreted to have mainly deposited in a fluvial depositional system. The High Cliff Sandstone, in contrast, contained two high resolution depositional sequences that displayed a coarsening upward sequences as supported by Gamma Ray log response and were interpreted to have mainly deposited in marginal marine settings. Reservoir properties modeling was also conducted utilizing the 3D models, where a 3D porosity model was calculated and shows that the Irwin River Coal Measures, in general, exhibit higher porosity distribution than the underlying High Cliff Sandstone, even though the later has coarser and more laterally extensive sand sheets. This is probably attributed to diagenetic porosity reduction within the High Cliff Sandstone caused by the formation waters. The calculated 3D water saturation model also confirms the presence of a single regional oil-water contact within the field and hence, reservoir heterogeneities and fault seal capacities did not affect the hydrocarbon distribution within the field. Finally, all the calculated models (e.g. lithofacies model, porosity model, and water saturation model) were integrated to estimate the recoverable hydrocarbons in place, where the Cliff Head is estimated to contain a total of 15.2 million barrels.
Cliff Head是北海珀斯盆地最重要的发现之一。因此，了解油田的构造和地质对进一步评价盆地海上区域至关重要。为了更好地理解这一领域，我们开发了两个结构模型。第一种模式主要针对二叠系及更老的地层，第二种模式针对上覆层。此外，还建立了储层物性模型(如孔隙度模型和含水饱和度模型)，以更好地了解储层相和油气分布。构造模型研究表明，断裂带主要有两组断裂，一组是针对晚二叠世不整合而截断的深二叠世断裂，另一组是早白垩世裂陷期发育的新白垩世断裂。研究还表明，油田内的油气在构造上被圈闭在二叠系古储层中，主要储集在欧文河煤系内。次级目标(如下伏的高崖砂岩)主要位于- 1257.8 m TVDss区域油水接触面以下，除了在油田最高构造点(Cliff Head-6)钻探。研究区欧文河煤系包含4个高分辨率的沉积层序，其伽马测井响应显示出向上细化的模式，主要为河流沉积体系。相比之下，高崖砂岩包含两个高分辨率的沉积层序，伽马测井响应支持其表现为粗化的向上层序，并解释为主要沉积于边缘海相环境。利用三维模型对储层进行了属性建模，计算了三维孔隙度模型，结果表明，Irwin River煤系总体上比下伏的High Cliff砂岩具有更高的孔隙度分布，尽管后者具有更粗、更横向扩展的砂层。这可能是由于地层水导致高崖砂岩内部成岩孔隙度降低所致。计算的三维含水饱和度模型也证实了油田内存在单一区域油水接触，因此，油藏非均质性和断层封闭能力不会影响油田内的油气分布。最后，综合所有计算模型(如岩相模型、孔隙度模型和含水饱和度模型)，估计Cliff Head地区的可采油气储量为1520万桶。
{"title":"The Geology and 3D Modelling of the Cliff Head Oil Field, Australia","authors":"Y. Eshmawi","doi":"10.2118/194954-MS","DOIUrl":"https://doi.org/10.2118/194954-MS","url":null,"abstract":"\u0000 The Cliff Head is one of the most significant discoveries in the offshore Northern Perth Basin. Hence, understanding the structure and geology of the field is essential to further evaluate the offshore region in the basin. Two structural models were developed with the objective to achieve a better understanding of this field. The first model is focused on the Permian and older strata, while the second model is for the overburden. In addition, reservoir properties models (e.g. porosity model and water saturation model) were developed to better understand the reservoir facies and hydrocarbon distribution. Examination of the structural models has shown that there are two main sets of faults within the Cliff Head area, which can be categorized into the following: the deep Permian faults that are truncated against the Late Permian unconformity, and younger Cretaceous faults that were developed during the Early Cretaceous rifting. It has also shown that the oil accumulation within the field is structurally trapped within Permian aged set of horsts and is mainly reservoired within the Irwin River Coal Measures. The secondary target (e.g. the underlying High Cliff Sandstone) is mostly beneath the regional oil-water contact of −1257.8 m TVDss, except in the highest structural point in the field, where Cliff Head-6 was drilled. The Irwin River Coal Measures in the study area contained four high resolution depositional sequences that displayed a finingupward pattern as depicted by the Gamma Ray log response and are interpreted to have mainly deposited in a fluvial depositional system. The High Cliff Sandstone, in contrast, contained two high resolution depositional sequences that displayed a coarsening upward sequences as supported by Gamma Ray log response and were interpreted to have mainly deposited in marginal marine settings. Reservoir properties modeling was also conducted utilizing the 3D models, where a 3D porosity model was calculated and shows that the Irwin River Coal Measures, in general, exhibit higher porosity distribution than the underlying High Cliff Sandstone, even though the later has coarser and more laterally extensive sand sheets. This is probably attributed to diagenetic porosity reduction within the High Cliff Sandstone caused by the formation waters. The calculated 3D water saturation model also confirms the presence of a single regional oil-water contact within the field and hence, reservoir heterogeneities and fault seal capacities did not affect the hydrocarbon distribution within the field. Finally, all the calculated models (e.g. lithofacies model, porosity model, and water saturation model) were integrated to estimate the recoverable hydrocarbons in place, where the Cliff Head is estimated to contain a total of 15.2 million barrels.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74197207","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}
S AbdulmalekAhmed, S. Elkatatny, Abdulwahab Ali, A. Abdulraheem, M. Mahmoud
Fracture pressure is a critical formation condition that affects efficiency and economy of drilling operations. The knowledge of the fracture pressure is significant to control the well. It will assist in avoiding problems associated with drilling operation and decreasing the cost of drilling operation. It is essential to predict fracture pressure accurately prior to drilling process to prevent various issues for example fluid loss, kicks, fracture the formation, differential pipe sticking, heaving shale and blowouts. Many models are used to estimate the fracture pressure either from log information or formation strengths. However, these models have some limitations such as some of the models can only be used in clean shales, applicable only for the pressure generated by under-compaction mechanism and some of them are not applicable in unloading formations. Few papers used artificial intelligence (AI) to estimate the fracture pressure. In this work, a real filed data that contain only the real time surface drilling parameters were utilized by artificial neural network (ANN) to predict the fracture pressure. The results indicated that artificial neural network (ANN) predicted the fracture pressures with an excellent precision where the coefficient of determination (R2) is greater than 0.99. In addition, the artificial neural network (ANN) was compared with other fracture pressure models such as Matthews and Kelly model, which is one of the most used models in the prediction of the fracture pressure in the field. Artificial neural network (ANN) model outperformed the fracture models by a high margin and by its simple prediction of fracture pressure where it can predict the fracture pressure from only the real time surface drilling parameters, which are easily available.
{"title":"Artificial Neural Network ANN Approach to Predict Fracture Pressure","authors":"S AbdulmalekAhmed, S. Elkatatny, Abdulwahab Ali, A. Abdulraheem, M. Mahmoud","doi":"10.2118/194852-MS","DOIUrl":"https://doi.org/10.2118/194852-MS","url":null,"abstract":"\u0000 Fracture pressure is a critical formation condition that affects efficiency and economy of drilling operations. The knowledge of the fracture pressure is significant to control the well. It will assist in avoiding problems associated with drilling operation and decreasing the cost of drilling operation. It is essential to predict fracture pressure accurately prior to drilling process to prevent various issues for example fluid loss, kicks, fracture the formation, differential pipe sticking, heaving shale and blowouts.\u0000 Many models are used to estimate the fracture pressure either from log information or formation strengths. However, these models have some limitations such as some of the models can only be used in clean shales, applicable only for the pressure generated by under-compaction mechanism and some of them are not applicable in unloading formations. Few papers used artificial intelligence (AI) to estimate the fracture pressure. In this work, a real filed data that contain only the real time surface drilling parameters were utilized by artificial neural network (ANN) to predict the fracture pressure.\u0000 The results indicated that artificial neural network (ANN) predicted the fracture pressures with an excellent precision where the coefficient of determination (R2) is greater than 0.99. In addition, the artificial neural network (ANN) was compared with other fracture pressure models such as Matthews and Kelly model, which is one of the most used models in the prediction of the fracture pressure in the field. Artificial neural network (ANN) model outperformed the fracture models by a high margin and by its simple prediction of fracture pressure where it can predict the fracture pressure from only the real time surface drilling parameters, which are easily available.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83559814","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 waterflooding, pore-throat structure of the porous media in the reservoir changes continually, which causes the great challenge in reservoir modeling and simulation. However, through the evolution mechanism of pore-throat characteristics for the reservoir during waterflooding has been intensively investigated in the past several decades, the essential controls on pore-throat structure evolution of reservoir rocks are not studied much. It is of theoretical and practical significance to use analytical methods to study the evolution of pore-throat characteristics of porous media during waterflooding. However, because of the disordered and extremely complicated microstructures of porous media, the theoretical model for stress sensitivity is scarce. The objective of this work is to establish a novel and reasonable quantitative model to determine the essential controls on pore-throat structure evolution of reservoir rocks. The theoretical model is derived from the fractal geometry. The predictions from the proposed model agree well with the available experimental data presented in the literature, which verified the novel quantitative model. There is no empirical constant and every parameter in the model has specific physical significance. In addition, the evolution rule for the pore-throat structure parameters has been obtained. The results show that the pore-throat structure of porous media becomes more complex and more heterogeneous after waterflooding. The pore-throat parameters (e.g. porosity, permeability, the maximum pore-throat radius, average pore-throat radius and sorting coefficient, etc.) will change during waterflooding. This work presents accurate and fast analytical models to perform the evolution rule of pore-throat characteristics of porous media during waterflooding. The proposed models can reveal more mechanisms that affect the coupled flow deformation behavior in porous media.
{"title":"Reservoir Pore-Throat Characteristics Evolution During Waterflooding: A Theoretical Study","authors":"G. Lei, Q. Liao, S. Patil","doi":"10.2118/195102-MS","DOIUrl":"https://doi.org/10.2118/195102-MS","url":null,"abstract":"\u0000 During waterflooding, pore-throat structure of the porous media in the reservoir changes continually, which causes the great challenge in reservoir modeling and simulation. However, through the evolution mechanism of pore-throat characteristics for the reservoir during waterflooding has been intensively investigated in the past several decades, the essential controls on pore-throat structure evolution of reservoir rocks are not studied much. It is of theoretical and practical significance to use analytical methods to study the evolution of pore-throat characteristics of porous media during waterflooding. However, because of the disordered and extremely complicated microstructures of porous media, the theoretical model for stress sensitivity is scarce. The objective of this work is to establish a novel and reasonable quantitative model to determine the essential controls on pore-throat structure evolution of reservoir rocks. The theoretical model is derived from the fractal geometry. The predictions from the proposed model agree well with the available experimental data presented in the literature, which verified the novel quantitative model. There is no empirical constant and every parameter in the model has specific physical significance. In addition, the evolution rule for the pore-throat structure parameters has been obtained. The results show that the pore-throat structure of porous media becomes more complex and more heterogeneous after waterflooding. The pore-throat parameters (e.g. porosity, permeability, the maximum pore-throat radius, average pore-throat radius and sorting coefficient, etc.) will change during waterflooding. This work presents accurate and fast analytical models to perform the evolution rule of pore-throat characteristics of porous media during waterflooding. The proposed models can reveal more mechanisms that affect the coupled flow deformation behavior in porous media.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84156103","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}
S. Maghrabi, Delores Smith, A. Engel, Jennifer Henry, Joseph Fandel
This presentation demonstrates further development of efficient primary and secondary emulsifiers for invert emulsion (oil-based) drilling fluids. These primary and secondary emulsifiers were developed from two separate refinery side streams of crude tall oil (CTO). Due to the high degree of compositional variation in these selected side streams, they were not historically considered for product development. We managed the composition variation challenge by setting precise specifications and connecting aspects of product composition with desired performance in the drilling fluid application. These side streams were derivatized under engineered reaction conditions to develop the efficient primary and secondary emulsifiers without compromising performance. Overall, detailed testing was performed to determine the emulsifier performance in different base oils (mineral oil and diesel), at different mud weights (12 – 16 ppg), at elevated temperatures, and in different fluid systems characterized by rheology and high-pressure, high-temperature (HPHT) fluid loss. Physical properties including product viscosity and pour points were also determined. The developed efficient primary and secondary emulsifiers performed on par or outperformed the industry-available emulsifiers tested in this study. The efficient primary emulsifier demonstrated lower pour points and lower product viscosity as compared to the industry standards tested in this study. A new field application of this efficient primary emulsifier in the U.S. will be presented. On the other hand, the secondary emulsifier provided stable rheology with improved controlled fluid loss as compared to the industry standards in both conventional and polymer fluids. The emulsifier package of the developed efficient primary and secondary emulsifiers provided stable fluids in various fluid systems which were composed of different viscosifiers and fluid loss additives (FLAs). The efficient primary and secondary emulsifiers were developed from highly variable raw materials. The physical properties of the primary emulsifier present it as a valued candidate for cold climate since it's easy to handle. The efficient secondary emulsifier can provide stable rheology with controlled fluid loss. The emulsifier package gave comparable performance across different fluid systems. This manuscript is a continuation of our previous research (Maghrabi et al. 2018).
本报告展示了用于反乳液(油基)钻井液的高效一级和二级乳化剂的进一步发展。这些一级和二级乳化剂是从两个独立的炼油厂原油侧流(CTO)中开发出来的。由于这些选择的侧流中成分的高度变化，它们在历史上没有被考虑用于产品开发。我们通过设定精确的规格，并将产品成分的各个方面与钻井液应用中的期望性能联系起来，来应对成分变化的挑战。这些侧流在工程反应条件下衍生，在不影响性能的情况下开发出高效的一级和二级乳化剂。总体而言，研究人员进行了详细的测试，以确定乳化剂在不同基础油(矿物油和柴油)、不同泥浆比重(12 - 16 ppg)、高温下的性能，以及在不同流变性和高压高温(HPHT)失滤的流体体系中的性能。物理性能包括产品粘度和倾点也被确定。所开发的高效一级和二级乳化剂的性能与本研究中测试的工业可用乳化剂相当或优于工业可用乳化剂。与本研究中测试的工业标准相比，高效的一级乳化剂显示出更低的倾点和更低的产品粘度。介绍了该高效一级乳化剂在美国的新应用情况。另一方面，与常规和聚合物流体的行业标准相比，二级乳化剂提供了稳定的流变性，并改善了流体损失的控制。所研制的高效一级和二级乳化剂的乳化剂包在由不同的增粘剂和降滤失剂(FLAs)组成的各种流体体系中提供稳定的流体。高效的一级和二级乳化剂是从高度可变的原料中开发出来的。初级乳化剂的物理性质使其成为寒冷气候的有价值的候选者，因为它易于处理。高效的二次乳化剂可以提供稳定的流变性和控制滤失。乳化剂包在不同的流体体系中具有相当的性能。这份手稿是我们之前研究的延续(Maghrabi et al. 2018)。
{"title":"Developing Efficient Emulsifiers for Improved Fluid Stability from Highly Variable Raw Materials: Performance Analysis and Field Application","authors":"S. Maghrabi, Delores Smith, A. Engel, Jennifer Henry, Joseph Fandel","doi":"10.2118/194734-MS","DOIUrl":"https://doi.org/10.2118/194734-MS","url":null,"abstract":"\u0000 This presentation demonstrates further development of efficient primary and secondary emulsifiers for invert emulsion (oil-based) drilling fluids. These primary and secondary emulsifiers were developed from two separate refinery side streams of crude tall oil (CTO). Due to the high degree of compositional variation in these selected side streams, they were not historically considered for product development. We managed the composition variation challenge by setting precise specifications and connecting aspects of product composition with desired performance in the drilling fluid application.\u0000 These side streams were derivatized under engineered reaction conditions to develop the efficient primary and secondary emulsifiers without compromising performance. Overall, detailed testing was performed to determine the emulsifier performance in different base oils (mineral oil and diesel), at different mud weights (12 – 16 ppg), at elevated temperatures, and in different fluid systems characterized by rheology and high-pressure, high-temperature (HPHT) fluid loss. Physical properties including product viscosity and pour points were also determined.\u0000 The developed efficient primary and secondary emulsifiers performed on par or outperformed the industry-available emulsifiers tested in this study. The efficient primary emulsifier demonstrated lower pour points and lower product viscosity as compared to the industry standards tested in this study. A new field application of this efficient primary emulsifier in the U.S. will be presented. On the other hand, the secondary emulsifier provided stable rheology with improved controlled fluid loss as compared to the industry standards in both conventional and polymer fluids. The emulsifier package of the developed efficient primary and secondary emulsifiers provided stable fluids in various fluid systems which were composed of different viscosifiers and fluid loss additives (FLAs).\u0000 The efficient primary and secondary emulsifiers were developed from highly variable raw materials. The physical properties of the primary emulsifier present it as a valued candidate for cold climate since it's easy to handle. The efficient secondary emulsifier can provide stable rheology with controlled fluid loss. The emulsifier package gave comparable performance across different fluid systems. This manuscript is a continuation of our previous research (Maghrabi et al. 2018).","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88700455","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}
Zhaoguang Yuan, Chukwuka Akpenyi, Daniel D. Carson, Zachary Hebert
The successful design and delivery of oil and gas production wells require significant levels of collaboration across multiple domains. The challenges encountered vary widely, and including risk evaluations from offset well analysis, domain-specific workflows and practices, geological concerns and limitations, engineering technology of choice, cost considerations, as well as environmental and safety concerns. Suboptimal levels of collaboration among team members, such as managers, geoscientists, drilling engineers, mud engineers, directional drillers, suppliers, and consultants, often negatively impact the quality or cost of the well. The application and analysis of a cloud technology in a case study shows how the cost of well planning can be significantly reduced, which enhances team collaboration and improves the process of engineering design. The digital well construction planning solution enables oil and gas operators to manage projects easily by: simplifying task assignment among drilling and operations team members, improving process status tracking, documenting the historical progress of each task, and opening access to industry-leading workflows and engines. This digital well construction planning solution which is deployed in the cloud, includes a project management structure, aiding with the assignment, review, and approval of tasks. Geoscientists and engineers can log in to the digital well construction planning solution, finish specific tasks, and then share the completed tasks with the rest of the project. This enables other team members whose design considerations have dependencies to incorporate holistic and representative design criteria into their own workflows. The process is smooth, concurrent, and evergreen, and all tasks are shared at both the output level and the engineering level. This approach ensures that the project data, workflows, and engineering analysis are always current. With this new solution, well planning time can be reduced from several days to a few hours. The project manager can easily track the status of each task without back-and-forth phone conversations or e-mails. With unconventional wells, where the well designs are often similar in the same region, template and project copy functions can be used to duplicate designs to the next well and accelerate the design process. After a project copy or template import is executed for a new project, the engineering validations can be produced after being shared. Trajectories can be designed automatically, incorporating anti-collision considerations, geological targets, well surface locations, and other design constraints. Then, well hydraulics, torque and drag analysis, bottomhole assembly (BHA) tendencies, and casing designs are validated to make sure the well is drillable and cost-effective. This digital well construction planning solution can help operators deliver safe, cost-effective wells on time, and execute high-quality well planning.
{"title":"Using Cloud Technology to Improve Unconventional Well Planning by Enhanced Collaboration and Automated Engineering Design","authors":"Zhaoguang Yuan, Chukwuka Akpenyi, Daniel D. Carson, Zachary Hebert","doi":"10.2118/194805-MS","DOIUrl":"https://doi.org/10.2118/194805-MS","url":null,"abstract":"\u0000 The successful design and delivery of oil and gas production wells require significant levels of collaboration across multiple domains. The challenges encountered vary widely, and including risk evaluations from offset well analysis, domain-specific workflows and practices, geological concerns and limitations, engineering technology of choice, cost considerations, as well as environmental and safety concerns. Suboptimal levels of collaboration among team members, such as managers, geoscientists, drilling engineers, mud engineers, directional drillers, suppliers, and consultants, often negatively impact the quality or cost of the well.\u0000 The application and analysis of a cloud technology in a case study shows how the cost of well planning can be significantly reduced, which enhances team collaboration and improves the process of engineering design. The digital well construction planning solution enables oil and gas operators to manage projects easily by: simplifying task assignment among drilling and operations team members, improving process status tracking, documenting the historical progress of each task, and opening access to industry-leading workflows and engines. This digital well construction planning solution which is deployed in the cloud, includes a project management structure, aiding with the assignment, review, and approval of tasks. Geoscientists and engineers can log in to the digital well construction planning solution, finish specific tasks, and then share the completed tasks with the rest of the project. This enables other team members whose design considerations have dependencies to incorporate holistic and representative design criteria into their own workflows. The process is smooth, concurrent, and evergreen, and all tasks are shared at both the output level and the engineering level. This approach ensures that the project data, workflows, and engineering analysis are always current.\u0000 With this new solution, well planning time can be reduced from several days to a few hours. The project manager can easily track the status of each task without back-and-forth phone conversations or e-mails. With unconventional wells, where the well designs are often similar in the same region, template and project copy functions can be used to duplicate designs to the next well and accelerate the design process. After a project copy or template import is executed for a new project, the engineering validations can be produced after being shared. Trajectories can be designed automatically, incorporating anti-collision considerations, geological targets, well surface locations, and other design constraints. Then, well hydraulics, torque and drag analysis, bottomhole assembly (BHA) tendencies, and casing designs are validated to make sure the well is drillable and cost-effective.\u0000 This digital well construction planning solution can help operators deliver safe, cost-effective wells on time, and execute high-quality well planning.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90935959","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}
Condensate blockage presents a serious production problem due to loss of gas productivity. Several methods have been proposed to resolve condensate blockage to restore the well productivity, most commonly used technique is hydraulic fracturing. Although, it is most commonly used, it is not always feasible and favorable due to its inclusion of costly chemicals such as surfactants, which could also be as hazardous material. Our objective in the current study, is replacing such surfactants with natural green surfactants which are more economical and environmentally friendly. Interfacial tension and contact angle experiments were carried out to examine the efficiency of two different natural green surfactants in comparison to two commonly used chemical surfactants in fracturing fluids. The results revealed that natural green surfactant is efficient in reducing the interfacial tension by 74.1% compared to 94.8% when using alcohol-based surfactants. Moreover, the natural green surfactant showed stronger effect in altering the surface wettability in sandstone formations towards strongly water-wet with a contact angle reduction of 61% compared to 32% in the case of alcohol-based surfactants. Based on the concentration used here, the natural green surfactants are more cost-effective, a product cost reduction of more than 50% can be obtained. Being efficient in reducing the interfacial tension, altering the surface wettability towards stronger water-wet, abundant in nature, environmentally friendly, and, cheaper cost, this new proposed natural surfactant can replace the currently used chemical surfactants for condensate bloackage.
{"title":"Innovative Green Solution for Gas Condensate Blockage Removal","authors":"Mohammed Al Hamad, E. Ibrahim, Wael Abdallah","doi":"10.2118/195143-MS","DOIUrl":"https://doi.org/10.2118/195143-MS","url":null,"abstract":"\u0000 Condensate blockage presents a serious production problem due to loss of gas productivity. Several methods have been proposed to resolve condensate blockage to restore the well productivity, most commonly used technique is hydraulic fracturing. Although, it is most commonly used, it is not always feasible and favorable due to its inclusion of costly chemicals such as surfactants, which could also be as hazardous material. Our objective in the current study, is replacing such surfactants with natural green surfactants which are more economical and environmentally friendly.\u0000 Interfacial tension and contact angle experiments were carried out to examine the efficiency of two different natural green surfactants in comparison to two commonly used chemical surfactants in fracturing fluids. The results revealed that natural green surfactant is efficient in reducing the interfacial tension by 74.1% compared to 94.8% when using alcohol-based surfactants. Moreover, the natural green surfactant showed stronger effect in altering the surface wettability in sandstone formations towards strongly water-wet with a contact angle reduction of 61% compared to 32% in the case of alcohol-based surfactants.\u0000 Based on the concentration used here, the natural green surfactants are more cost-effective, a product cost reduction of more than 50% can be obtained. Being efficient in reducing the interfacial tension, altering the surface wettability towards stronger water-wet, abundant in nature, environmentally friendly, and, cheaper cost, this new proposed natural surfactant can replace the currently used chemical surfactants for condensate bloackage.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91346903","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. Arsalan, T. J. Ahmad, Weichang Li, Robert W. Adams, M. Deffenbaugh
Multiphase flow meters are available from sometime, however, there still remain unresolved challenges. Dependable flow sensing is essential for reservoir management and production optimization. Most commercial water-cut and multiphase flow meters have limitations while measuring over the full range of flow conditions. Exiting meters need recurrent calibration, and have significant capital and operational overheads. In this paper an ultrasonic tomography based meter for water hold-up measurement is presented and the the experiences and challenges of testing the system in the field are shared. The designed system has the potential to resolve the shortcomings of available multiphase metering solutions.
{"title":"Ultrasound Tomography Based Flow Measurement System; Field Experiences","authors":"M. Arsalan, T. J. Ahmad, Weichang Li, Robert W. Adams, M. Deffenbaugh","doi":"10.2118/194761-MS","DOIUrl":"https://doi.org/10.2118/194761-MS","url":null,"abstract":"\u0000 Multiphase flow meters are available from sometime, however, there still remain unresolved challenges. Dependable flow sensing is essential for reservoir management and production optimization. Most commercial water-cut and multiphase flow meters have limitations while measuring over the full range of flow conditions. Exiting meters need recurrent calibration, and have significant capital and operational overheads. In this paper an ultrasonic tomography based meter for water hold-up measurement is presented and the the experiences and challenges of testing the system in the field are shared. The designed system has the potential to resolve the shortcomings of available multiphase metering solutions.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88041153","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. T. Al-Murayri, A. Hassan, I. Hénaut, C. Marliere, A. Mouret, D. Lalanne-Aulet, Juan-Pablo Sanchez, G. Suzanne
This study presents an integrated approach to design a fit-for-purpose surfactant-polymer process for a major sandstone reservoir in Kuwait. The adopted procedure is described covering core flood experiments through pilot design using a reservoir simulation tool that was calibrated using laboratory results. The surfactant-polymer formulation design was already described in another publication (SPE-183933). In this paper, further optimization of the chemical formulation is described, including core floods to minimize the quantity of the injected chemicals while maintaining high oil recovery. Formulation robustness and its impacts on water-oil separation at the surface are also evaluated. Furthermore, reservoir simulation was utilized to design a field trial. At first, the parameters that were used to model surfactant-polymer performance were calibrated using core flood results. Then, the reservoir simulation model was used at a larger scale to identify the most appropriate injection sequence for field implementation. The performance of the designed surfactant-polymer formulation is promising. Core flood experiments demonstrate that the injection of the chemical formulation recovers more than 85% of the remaining oil after waterflooding, while having relatively low adsorption values. The designed formulation was also found to be quite resilient to variations in divalent cations concentration, water-oil ratio and oil composition. It was noticed that rock facies heterogeneity has a limited effect on surfactant adsorption. Favorable phase behavior properties were maintained around reservoir temperature and the formulation exhibited good aqueous stability between reservoir and surface temperatures. EOR parameters including salinity-dependent surfactant adsorption, capillary desaturation and polymer-induced water mobility reduction were calibrated in the reservoir simulation model using core flood data. Larger scale reservoir simulation enabled the design of a suitable injection sequence including a main surfactant-polymer slug followed by a polymer slug. The main variables of the design, including slug injection durations, chemical concentrations and pattern size were optimized through numerous sensitivity scenarios. Using a 5-spot pattern with a spacing of 75 m, surfactant-polymer injection effects should be observed within a short timeframe of around 14 months. This paper describes a successful approach to design a surfactant-polymer process, integrating laboratory experiments and reservoir simulation. This work paves the way for a 5-spot EOR pilot involving a major sandstone reservoir and will undoubtedly provide valuable insights for chemical EOR applications in similar reservoirs elsewhere.
{"title":"Surfactant-Polymer Feasibility for a Sandstone Reservoir in Kuwait. Successful Integrated Approach from Laboratory to Pilot Design","authors":"M. T. Al-Murayri, A. Hassan, I. Hénaut, C. Marliere, A. Mouret, D. Lalanne-Aulet, Juan-Pablo Sanchez, G. Suzanne","doi":"10.2118/194979-MS","DOIUrl":"https://doi.org/10.2118/194979-MS","url":null,"abstract":"\u0000 This study presents an integrated approach to design a fit-for-purpose surfactant-polymer process for a major sandstone reservoir in Kuwait. The adopted procedure is described covering core flood experiments through pilot design using a reservoir simulation tool that was calibrated using laboratory results.\u0000 The surfactant-polymer formulation design was already described in another publication (SPE-183933). In this paper, further optimization of the chemical formulation is described, including core floods to minimize the quantity of the injected chemicals while maintaining high oil recovery. Formulation robustness and its impacts on water-oil separation at the surface are also evaluated. Furthermore, reservoir simulation was utilized to design a field trial. At first, the parameters that were used to model surfactant-polymer performance were calibrated using core flood results. Then, the reservoir simulation model was used at a larger scale to identify the most appropriate injection sequence for field implementation.\u0000 The performance of the designed surfactant-polymer formulation is promising. Core flood experiments demonstrate that the injection of the chemical formulation recovers more than 85% of the remaining oil after waterflooding, while having relatively low adsorption values. The designed formulation was also found to be quite resilient to variations in divalent cations concentration, water-oil ratio and oil composition. It was noticed that rock facies heterogeneity has a limited effect on surfactant adsorption. Favorable phase behavior properties were maintained around reservoir temperature and the formulation exhibited good aqueous stability between reservoir and surface temperatures. EOR parameters including salinity-dependent surfactant adsorption, capillary desaturation and polymer-induced water mobility reduction were calibrated in the reservoir simulation model using core flood data. Larger scale reservoir simulation enabled the design of a suitable injection sequence including a main surfactant-polymer slug followed by a polymer slug. The main variables of the design, including slug injection durations, chemical concentrations and pattern size were optimized through numerous sensitivity scenarios. Using a 5-spot pattern with a spacing of 75 m, surfactant-polymer injection effects should be observed within a short timeframe of around 14 months.\u0000 This paper describes a successful approach to design a surfactant-polymer process, integrating laboratory experiments and reservoir simulation. This work paves the way for a 5-spot EOR pilot involving a major sandstone reservoir and will undoubtedly provide valuable insights for chemical EOR applications in similar reservoirs elsewhere.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87930095","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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