Abstract The influence of geological and engineering factors results in the complex production characteristics of shale gas wells. The productivity evaluation method is effective to analyze the production decline law and estimate the ultimate recovery in the shale gas reservoir. This paper reviews the production decline method, analytical method, numerical simulation method, and machine learning method. which analyzes the applicable conditions, basic principles, characteristics, and limitations of different methods. The research found that the production decline method can mainly account for the gas well production and pressure data by fitting type curve analysis. The analytical method is able to couple multiple transport mechanisms and quantify the impact of different mechanisms on shale gas well productivity. Numerical simulation builds multiple pore media in shale gas reservoirs and performs production dynamics as well as capacity prediction visually. Machine learning methods are a nascent approach that can efficiently use available production data from shale gas wells to predict productivity. Finally, the research discusses the future directions and challenges of shale gas well productivity evaluation methods.
{"title":"Review of the productivity evaluation methods for shale gas wells","authors":"Yize Huang, Xizhe Li, Xiaohua Liu, Yujia Zhai, Feifei Fang, Wei Guo, Chao Qian, Lingling Han, Yue Cui, Yuze Jia","doi":"10.1007/s13202-023-01698-z","DOIUrl":"https://doi.org/10.1007/s13202-023-01698-z","url":null,"abstract":"Abstract The influence of geological and engineering factors results in the complex production characteristics of shale gas wells. The productivity evaluation method is effective to analyze the production decline law and estimate the ultimate recovery in the shale gas reservoir. This paper reviews the production decline method, analytical method, numerical simulation method, and machine learning method. which analyzes the applicable conditions, basic principles, characteristics, and limitations of different methods. The research found that the production decline method can mainly account for the gas well production and pressure data by fitting type curve analysis. The analytical method is able to couple multiple transport mechanisms and quantify the impact of different mechanisms on shale gas well productivity. Numerical simulation builds multiple pore media in shale gas reservoirs and performs production dynamics as well as capacity prediction visually. Machine learning methods are a nascent approach that can efficiently use available production data from shale gas wells to predict productivity. Finally, the research discusses the future directions and challenges of shale gas well productivity evaluation methods.","PeriodicalId":16723,"journal":{"name":"Journal of Petroleum Exploration and Production Technology","volume":"49 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135095722","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-09-28DOI: 10.1007/s13202-023-01706-2
Md. Ashiqul Islam Shuvo, Md. Zayed Bin Sultan, A. R. Rafi Ferdous
Abstract Drilling fluid is essential to oil and gas drilling operations due to its diverse functionality. But the most commonly used drilling fluid additives are hazardous chemicals and are not biodegradable. As a result, the demand for environment-friendly additives has been raised to replace the hazardous chemical additives. Considering the rising interest toward green additive, this study examined the applicability of sawdust to be used as a biodegradable drilling fluid additive to improve the rheological and filtration properties of water-based mud. Sawdust was chosen for this study because of its high cellulose content, widespread availability, and low cost. Following the guidelines set by the American Petroleum Institute (API), we carried out laboratory experiments that encompassed three distinct concentrations of sawdust: sample 1 (with 0.25% sawdust), sample 2 (with 0.50% sawdust), and sample 3 (with 0.75% sawdust). The concentrations of sawdust were measured as a weight percentage of the total volume of the base water. Concentrations above 0.75% led to gelation issues. Results showed minimal impact on mud weight at 0.25% sawdust, while 0.50 and 0.75% concentrations caused slight weight reduction due to foam development. Plastic viscosity increased by 28.5, 42.8, and 71.4% for sample 1, sample 2, and sample 3, respectively, compared to the base mud. Sawdust-containing mud exhibited desirable gel strength and shear-thinning behavior. Moreover, sawdust significantly improved filtration properties by reducing fluid loss and mud cake thickness. Sample 2 (0.5% sawdust) performed well in terms of filtration properties. Mud cake permeability followed the trend: $${k}_{mathrm{BM}}>{k}_{0.75% mathrm{sawdust}}>{k}_{0.25% mathrm{sawdust}}>{k}_{0.50% mathrm{sawdust}}$$ kBM>k0.75%sawdust>k0.25%sawdust>k0.50%sawdust . Based on promising laboratory performance, lower concentrations of sawdust are recommended as a cost-effective and eco-friendly additive to enhance rheological and filtration properties of water-based drilling fluid systems.
摘要钻井液具有多种功能，在油气钻井作业中起着至关重要的作用。但是最常用的钻井液添加剂是有害的化学物质，并且是不可生物降解的。因此，人们提出了对环保型添加剂的需求，以取代有害的化学添加剂。考虑到人们对绿色添加剂的兴趣日益浓厚，本研究考察了木屑作为可生物降解钻井液添加剂的适用性，以改善水基泥浆的流变学和过滤性能。选择木屑作为研究对象是因为木屑纤维素含量高、可获得性广、成本低。根据美国石油协会(API)制定的指导方针，我们进行了包含三种不同浓度木屑的实验室实验:样品1 (0.25)% sawdust), sample 2 (with 0.50% sawdust), and sample 3 (with 0.75% sawdust). The concentrations of sawdust were measured as a weight percentage of the total volume of the base water. Concentrations above 0.75% led to gelation issues. Results showed minimal impact on mud weight at 0.25% sawdust, while 0.50 and 0.75% concentrations caused slight weight reduction due to foam development. Plastic viscosity increased by 28.5, 42.8, and 71.4% for sample 1, sample 2, and sample 3, respectively, compared to the base mud. Sawdust-containing mud exhibited desirable gel strength and shear-thinning behavior. Moreover, sawdust significantly improved filtration properties by reducing fluid loss and mud cake thickness. Sample 2 (0.5% sawdust) performed well in terms of filtration properties. Mud cake permeability followed the trend: $${k}_{mathrm{BM}}>{k}_{0.75% mathrm{sawdust}}>{k}_{0.25% mathrm{sawdust}}>{k}_{0.50% mathrm{sawdust}}$$ k BM > k 0.75 % sawdust > k 0.25 % sawdust > k 0.50 % sawdust . Based on promising laboratory performance, lower concentrations of sawdust are recommended as a cost-effective and eco-friendly additive to enhance rheological and filtration properties of water-based drilling fluid systems.
{"title":"Applicability of sawdust as a green additive to improve the rheological and filtration properties of water-based drilling fluid: an experimental investigation","authors":"Md. Ashiqul Islam Shuvo, Md. Zayed Bin Sultan, A. R. Rafi Ferdous","doi":"10.1007/s13202-023-01706-2","DOIUrl":"https://doi.org/10.1007/s13202-023-01706-2","url":null,"abstract":"Abstract Drilling fluid is essential to oil and gas drilling operations due to its diverse functionality. But the most commonly used drilling fluid additives are hazardous chemicals and are not biodegradable. As a result, the demand for environment-friendly additives has been raised to replace the hazardous chemical additives. Considering the rising interest toward green additive, this study examined the applicability of sawdust to be used as a biodegradable drilling fluid additive to improve the rheological and filtration properties of water-based mud. Sawdust was chosen for this study because of its high cellulose content, widespread availability, and low cost. Following the guidelines set by the American Petroleum Institute (API), we carried out laboratory experiments that encompassed three distinct concentrations of sawdust: sample 1 (with 0.25% sawdust), sample 2 (with 0.50% sawdust), and sample 3 (with 0.75% sawdust). The concentrations of sawdust were measured as a weight percentage of the total volume of the base water. Concentrations above 0.75% led to gelation issues. Results showed minimal impact on mud weight at 0.25% sawdust, while 0.50 and 0.75% concentrations caused slight weight reduction due to foam development. Plastic viscosity increased by 28.5, 42.8, and 71.4% for sample 1, sample 2, and sample 3, respectively, compared to the base mud. Sawdust-containing mud exhibited desirable gel strength and shear-thinning behavior. Moreover, sawdust significantly improved filtration properties by reducing fluid loss and mud cake thickness. Sample 2 (0.5% sawdust) performed well in terms of filtration properties. Mud cake permeability followed the trend: $${k}_{mathrm{BM}}>{k}_{0.75% mathrm{sawdust}}>{k}_{0.25% mathrm{sawdust}}>{k}_{0.50% mathrm{sawdust}}$$ <mml:math xmlns:mml=\"http://www.w3.org/1998/Math/MathML\"> <mml:mrow> <mml:msub> <mml:mi>k</mml:mi> <mml:mi>BM</mml:mi> </mml:msub> <mml:mo>></mml:mo> <mml:msub> <mml:mi>k</mml:mi> <mml:mrow> <mml:mn>0.75</mml:mn> <mml:mo>%</mml:mo> <mml:mi>sawdust</mml:mi> </mml:mrow> </mml:msub> <mml:mo>></mml:mo> <mml:msub> <mml:mi>k</mml:mi> <mml:mrow> <mml:mn>0.25</mml:mn> <mml:mo>%</mml:mo> <mml:mi>sawdust</mml:mi> </mml:mrow> </mml:msub> <mml:mo>></mml:mo> <mml:msub> <mml:mi>k</mml:mi> <mml:mrow> <mml:mn>0.50</mml:mn> <mml:mo>%</mml:mo> <mml:mi>sawdust</mml:mi> </mml:mrow> </mml:msub> </mml:mrow> </mml:math> . Based on promising laboratory performance, lower concentrations of sawdust are recommended as a cost-effective and eco-friendly additive to enhance rheological and filtration properties of water-based drilling fluid systems.","PeriodicalId":16723,"journal":{"name":"Journal of Petroleum Exploration and Production Technology","volume":"60 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135344549","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-09-27DOI: 10.1007/s13202-023-01701-7
Chengting Liu, Chuanfeng Hu, Tian Chen, Zhao Yang, Luna Wang
Abstract Daqing Oilfield as the world’s largest application area of alkali–surfactant–polymer (ASP) flooding, in recent years, with the increase in aging wells, the eccentric wear and deformation of sucker rod and pipe during oil production has become more and more serious. In order to study the effect of emulsion lubrication in ternary composite flooding on eccentric wear of sucker rod and tubing, this paper establishes a calculation model for the depth of tubing wear under different emulsion lubrication conditions through indoor friction and wear experiments combined with White and Dawson wear efficiency theory. Based on this, the finite element method is used to predict the safe wear life of tubing under different component emulsion lubrication. The results show that compared to intact oil pipes, the residual internal pressure strength of oil pipes with defects decreases, and stress concentration occurs at the edges and middle of the defects. The wear life of oil pipes decreases with the increase in pump depth and wear coefficient under emulsion lubrication. The water content and alkali concentration have the most significant effects on the wear life of oil pipes under emulsion lubrication conditions. The safe wear life of sucker rod pipes under emulsion lubrication with a water content of 75% will be increased by 37.8% compared to those in emulsion lubrication with a water content of 95%, and under emulsion lubrication with an alkali concentration of 500 mg/l, the safe wear life will be increased by 50.6% compared to those in emulsion lubrication with a concentration of 2000 mg/l. The research results can provide theoretical and technical support for oilfield enterprises to reduce rod and pipe wear in ASP flooding oil wells, improve the pump inspection cycle of pumping wells, and ensure the safety of oil well work.
{"title":"Wear analysis and life prediction of sucker rod and tubing under ternary emulsion lubrication in Daqing oilfield: a case study in block H","authors":"Chengting Liu, Chuanfeng Hu, Tian Chen, Zhao Yang, Luna Wang","doi":"10.1007/s13202-023-01701-7","DOIUrl":"https://doi.org/10.1007/s13202-023-01701-7","url":null,"abstract":"Abstract Daqing Oilfield as the world’s largest application area of alkali–surfactant–polymer (ASP) flooding, in recent years, with the increase in aging wells, the eccentric wear and deformation of sucker rod and pipe during oil production has become more and more serious. In order to study the effect of emulsion lubrication in ternary composite flooding on eccentric wear of sucker rod and tubing, this paper establishes a calculation model for the depth of tubing wear under different emulsion lubrication conditions through indoor friction and wear experiments combined with White and Dawson wear efficiency theory. Based on this, the finite element method is used to predict the safe wear life of tubing under different component emulsion lubrication. The results show that compared to intact oil pipes, the residual internal pressure strength of oil pipes with defects decreases, and stress concentration occurs at the edges and middle of the defects. The wear life of oil pipes decreases with the increase in pump depth and wear coefficient under emulsion lubrication. The water content and alkali concentration have the most significant effects on the wear life of oil pipes under emulsion lubrication conditions. The safe wear life of sucker rod pipes under emulsion lubrication with a water content of 75% will be increased by 37.8% compared to those in emulsion lubrication with a water content of 95%, and under emulsion lubrication with an alkali concentration of 500 mg/l, the safe wear life will be increased by 50.6% compared to those in emulsion lubrication with a concentration of 2000 mg/l. The research results can provide theoretical and technical support for oilfield enterprises to reduce rod and pipe wear in ASP flooding oil wells, improve the pump inspection cycle of pumping wells, and ensure the safety of oil well work.","PeriodicalId":16723,"journal":{"name":"Journal of Petroleum Exploration and Production Technology","volume":"40 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135537829","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-09-22DOI: 10.1007/s13202-023-01703-5
Lin Jiang, Yan Song, Wen Zhao, Dongmei Bo, Shaobo Liu, Jiaqing Hao
Abstract Despite the significant progress made in coalbed methane (CBM) exploration and development in recent years, understanding of CBM enrichment mechanisms remains limited. This study aims to elucidate the CBM enrichment mechanism in the southern Qinshui Basin, China, by analyzing characteristics of global CBM basins and building a geological model of the study area. Field analyses are conducted to predict sweet spots of high CBM abundance and production potential. The findings reveal a high-yield model of CBM accumulation at relatively elevated structural positions within enriched areas. Compared to other global basins, low permeability poses the primary challenge for CBM development in China. Coal seam thickness shows minimal variation in southern Qinshui Basin, exerting negligible impact on CBM productivity. The shallow burial depth of coal seams in this region results in low stress, conferring high permeability conducive to high CBM yields. In situ stress conditions exert a primary control on the development of microfracture systems, which in turn govern reservoir permeability. This work provides new insights into CBM enrichment patterns in the southern Qinshui Basin. The proposed high-yield model enables better understanding of favorable conditions for CBM accumulation. Overall, this study represents a valuable contribution toward unlocking China’s CBM potential through improved geological characterization.
{"title":"Main controlling factor of coalbed methane enrichment area in southern Qinshui Basin, China","authors":"Lin Jiang, Yan Song, Wen Zhao, Dongmei Bo, Shaobo Liu, Jiaqing Hao","doi":"10.1007/s13202-023-01703-5","DOIUrl":"https://doi.org/10.1007/s13202-023-01703-5","url":null,"abstract":"Abstract Despite the significant progress made in coalbed methane (CBM) exploration and development in recent years, understanding of CBM enrichment mechanisms remains limited. This study aims to elucidate the CBM enrichment mechanism in the southern Qinshui Basin, China, by analyzing characteristics of global CBM basins and building a geological model of the study area. Field analyses are conducted to predict sweet spots of high CBM abundance and production potential. The findings reveal a high-yield model of CBM accumulation at relatively elevated structural positions within enriched areas. Compared to other global basins, low permeability poses the primary challenge for CBM development in China. Coal seam thickness shows minimal variation in southern Qinshui Basin, exerting negligible impact on CBM productivity. The shallow burial depth of coal seams in this region results in low stress, conferring high permeability conducive to high CBM yields. In situ stress conditions exert a primary control on the development of microfracture systems, which in turn govern reservoir permeability. This work provides new insights into CBM enrichment patterns in the southern Qinshui Basin. The proposed high-yield model enables better understanding of favorable conditions for CBM accumulation. Overall, this study represents a valuable contribution toward unlocking China’s CBM potential through improved geological characterization.","PeriodicalId":16723,"journal":{"name":"Journal of Petroleum Exploration and Production Technology","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136011705","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Abstract The complex application of modern analysis methods (FT-IR, NMR, GC–MS and UV/Vis) allowed us to study in detail the composition of the crude Surakhani light oil with a complex composition. An accurate and comprehensive study of the composition of crude oils makes it easier to find the necessary field of application for them. For this purpose, the studied crude oil was separated into two fractions, such as paraffinic–naphthenic and aromatic (groups 1st, 2nd, 3rd and tar), by absorption column chromatography. The results show that Surakhani light oil is a paraffin–naphthene-based oil that contains 74% of paraffin–naphthene, 11.15% of aromatic hydrocarbons and 14.8% of gases. It has been shown that the aromatic group of compounds is mainly composed of mono- and bicyclic compounds and has alkyl chains with different lengths and branches (with the presence of methylene and methine groups). Based on the parameters of the structural group, it was found that the portion of H atoms in the aromatic nucleus and alkyl chain was 4.4–20.1% and 79.9–95.6%, respectively. The degree of aromaticity of the separated aromatic group is approximately 50%, which proves that these compounds are alkylated. The structure of the isolated paraffin–naphthene fraction has also been investigated by spectroscopic techniques, and it has been determined that this fraction is composed of iso- and cycloalkanes with alkyl chains of different lengths. As it is seen from the obtained results, unlike the other oils existing on the Absheron Peninsula, Surakhani light oil consists of one- and two-ring naphthene and isostructured paraffinic hydrocarbons. The composition of this petroleum mainly consists of isosubstituted alkyl cycloalkanes and relict, viz. biologically active hydrocarbons such as sterane and hopane used in medicine. It seems that the methodology developed for the petroleum industry can be used in other fields such as medicine. Graphical abstract
{"title":"Investigation of Surakhani light crude oil compounds as a case study using modern spectroscopic techniques","authors":"Ulviyya Yolchuyeva, Rena Japharova, Matlab Khamiyev, Fakhranda Alimardanova","doi":"10.1007/s13202-023-01702-6","DOIUrl":"https://doi.org/10.1007/s13202-023-01702-6","url":null,"abstract":"Abstract The complex application of modern analysis methods (FT-IR, NMR, GC–MS and UV/Vis) allowed us to study in detail the composition of the crude Surakhani light oil with a complex composition. An accurate and comprehensive study of the composition of crude oils makes it easier to find the necessary field of application for them. For this purpose, the studied crude oil was separated into two fractions, such as paraffinic–naphthenic and aromatic (groups 1st, 2nd, 3rd and tar), by absorption column chromatography. The results show that Surakhani light oil is a paraffin–naphthene-based oil that contains 74% of paraffin–naphthene, 11.15% of aromatic hydrocarbons and 14.8% of gases. It has been shown that the aromatic group of compounds is mainly composed of mono- and bicyclic compounds and has alkyl chains with different lengths and branches (with the presence of methylene and methine groups). Based on the parameters of the structural group, it was found that the portion of H atoms in the aromatic nucleus and alkyl chain was 4.4–20.1% and 79.9–95.6%, respectively. The degree of aromaticity of the separated aromatic group is approximately 50%, which proves that these compounds are alkylated. The structure of the isolated paraffin–naphthene fraction has also been investigated by spectroscopic techniques, and it has been determined that this fraction is composed of iso- and cycloalkanes with alkyl chains of different lengths. As it is seen from the obtained results, unlike the other oils existing on the Absheron Peninsula, Surakhani light oil consists of one- and two-ring naphthene and isostructured paraffinic hydrocarbons. The composition of this petroleum mainly consists of isosubstituted alkyl cycloalkanes and relict, viz. biologically active hydrocarbons such as sterane and hopane used in medicine. It seems that the methodology developed for the petroleum industry can be used in other fields such as medicine. Graphical abstract","PeriodicalId":16723,"journal":{"name":"Journal of Petroleum Exploration and Production Technology","volume":"175 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136310935","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-09-19DOI: 10.1007/s13202-023-01696-1
Min Lv, Bo Xue, Weipeng Guo, Jing Li, Bin Guan
Abstract The prediction of production capacity in tight gas wells is greatly influenced by the characteristics of gas–water two-phase flow and the fracture network permeability parameters. However, traditional analytical models simplify the nonlinear problems of two-phase flow equations to a large extent, resulting in significant errors in dynamic analysis results. To address this issue, this study considers the characteristics of gas–water two-phase flow in the reservoir and fracture network, utilizes a trilinear flow model to characterize the effects of hydraulic fracturing, and takes into account the stress sensitivity of the reservoir and fractures. A predictive model for gas–water two-phase production in tight fractured horizontal wells is established. By combining the mass balance equation with the Newton–Raphson iteration method, the nonlinear parameters of the flow model are updated step by step using the average reservoir pressure. The accuracy of the model is validated through comparisons with results from commercial numerical simulation software and field case applications. The research results demonstrate that the established semi-analytical solution method efficiently handles the nonlinear two-phase flow problems, allowing for the rapid and accurate prediction of production capacity in tight gas wells. Water production significantly affects gas well productivity, and appropriate fracture network parameters are crucial for improving gas well productivity. The findings of this work could provide more clear understanding of the gas production performance from the fractured tight-gas horizontal well.
{"title":"Novel calculation method to predict gas–water two-phase production for the fractured tight-gas horizontal well","authors":"Min Lv, Bo Xue, Weipeng Guo, Jing Li, Bin Guan","doi":"10.1007/s13202-023-01696-1","DOIUrl":"https://doi.org/10.1007/s13202-023-01696-1","url":null,"abstract":"Abstract The prediction of production capacity in tight gas wells is greatly influenced by the characteristics of gas–water two-phase flow and the fracture network permeability parameters. However, traditional analytical models simplify the nonlinear problems of two-phase flow equations to a large extent, resulting in significant errors in dynamic analysis results. To address this issue, this study considers the characteristics of gas–water two-phase flow in the reservoir and fracture network, utilizes a trilinear flow model to characterize the effects of hydraulic fracturing, and takes into account the stress sensitivity of the reservoir and fractures. A predictive model for gas–water two-phase production in tight fractured horizontal wells is established. By combining the mass balance equation with the Newton–Raphson iteration method, the nonlinear parameters of the flow model are updated step by step using the average reservoir pressure. The accuracy of the model is validated through comparisons with results from commercial numerical simulation software and field case applications. The research results demonstrate that the established semi-analytical solution method efficiently handles the nonlinear two-phase flow problems, allowing for the rapid and accurate prediction of production capacity in tight gas wells. Water production significantly affects gas well productivity, and appropriate fracture network parameters are crucial for improving gas well productivity. The findings of this work could provide more clear understanding of the gas production performance from the fractured tight-gas horizontal well.","PeriodicalId":16723,"journal":{"name":"Journal of Petroleum Exploration and Production Technology","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135015609","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-09-15DOI: 10.1007/s13202-023-01700-8
Muhammad Hammad Rasool, Maqsood Ahmad
Abstract Shale instability is a significant problem, accounting for approximately 70% of wellbore challenges during drilling operations. To address this issue, shale inhibitors are commonly added to drilling mud to stabilize the encountered shale formations. Ionic liquids and deep eutectic solvents have been recognized as effective shale inhibitors due to their environmental friendliness and effectiveness. However, despite their advantages, these solutions still lack full environmental sustainability, leading researchers to explore more natural alternatives like Natural Deep Eutectic Solvents (NADES). This study focuses on the synthesis and application of a NADES composed of Potassium Chloride (KCl) and glycerine, aiming to enhance the environmental profile and efficacy of shale inhibitors. The NADES was prepared with a 1:8 molar ratio at a temperature of 60 °C. Characterization analyses, including Fourier Transform Infrared and Thermogravimetric Analysis, confirmed the formation of bonds between –(OH) and Cl − and demonstrated the NADES's thermal stability up to 200 °C. Incorporating 3% NADES into water-based mud, prepared following API 13B-1 standards, resulted in significant improvements in mud rheology. Specifically, the addition of 3% NADES reduced filtrate volume by 14.2% and mud cake thickness by 19.2%. Furthermore, the 3% NADES exhibited remarkable inhibition of clay swelling by 69.23% and demonstrated a shale recovery rate of 58%. When compared with 3% KCl and 3% 1-ethyl-3-methylimidazolium chloride (EMIM-Cl), the NADES-based mud outperformed both in terms of efficacy. These findings were further supported by additional analyses, including d-spacing measurements (XRD), Zeta Potential, Surface tension, and Field Emission Scanning Electron Microscopy. Additionally, the rheological behavior of the NADES-based mud aligned with the Yield Power Law at both 25 °C and 100 °C. The study's findings contribute to the advancement of greener drilling practices and highlight the applicability of KCl-based NADES as a potential drilling fluid additive.
{"title":"Revolutionizing shale drilling with potassium chloride-based natural deep eutectic solvent as an additive","authors":"Muhammad Hammad Rasool, Maqsood Ahmad","doi":"10.1007/s13202-023-01700-8","DOIUrl":"https://doi.org/10.1007/s13202-023-01700-8","url":null,"abstract":"Abstract Shale instability is a significant problem, accounting for approximately 70% of wellbore challenges during drilling operations. To address this issue, shale inhibitors are commonly added to drilling mud to stabilize the encountered shale formations. Ionic liquids and deep eutectic solvents have been recognized as effective shale inhibitors due to their environmental friendliness and effectiveness. However, despite their advantages, these solutions still lack full environmental sustainability, leading researchers to explore more natural alternatives like Natural Deep Eutectic Solvents (NADES). This study focuses on the synthesis and application of a NADES composed of Potassium Chloride (KCl) and glycerine, aiming to enhance the environmental profile and efficacy of shale inhibitors. The NADES was prepared with a 1:8 molar ratio at a temperature of 60 °C. Characterization analyses, including Fourier Transform Infrared and Thermogravimetric Analysis, confirmed the formation of bonds between –(OH) and Cl − and demonstrated the NADES's thermal stability up to 200 °C. Incorporating 3% NADES into water-based mud, prepared following API 13B-1 standards, resulted in significant improvements in mud rheology. Specifically, the addition of 3% NADES reduced filtrate volume by 14.2% and mud cake thickness by 19.2%. Furthermore, the 3% NADES exhibited remarkable inhibition of clay swelling by 69.23% and demonstrated a shale recovery rate of 58%. When compared with 3% KCl and 3% 1-ethyl-3-methylimidazolium chloride (EMIM-Cl), the NADES-based mud outperformed both in terms of efficacy. These findings were further supported by additional analyses, including d-spacing measurements (XRD), Zeta Potential, Surface tension, and Field Emission Scanning Electron Microscopy. Additionally, the rheological behavior of the NADES-based mud aligned with the Yield Power Law at both 25 °C and 100 °C. The study's findings contribute to the advancement of greener drilling practices and highlight the applicability of KCl-based NADES as a potential drilling fluid additive.","PeriodicalId":16723,"journal":{"name":"Journal of Petroleum Exploration and Production Technology","volume":"55 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135436290","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-09-14DOI: 10.1007/s13202-023-01699-y
Kartika F. Hartono, Asep K. Permadi, Ucok W. R. Siagian, Andri L. L. Hakim, Sumadi Paryoto, Ahlul H. Resha, Yudistira Adinugraha, Egi A. Pratama
Abstract Numerous studies have investigated the fundamental mechanisms by which CO 2 flooding can increase oil production by altering the properties of the hydrocarbon fluid, including oil swelling, viscosity and interfacial tension reductions, and the extraction of light-to-intermediate components. However, the interactions between CO 2 and hydrocarbon fluid may also cause several problems, such as asphaltene precipitation due to crude oil's instability during the CO 2 flooding process. This study investigates the complex factors that affect the instability of crude oil, including CO 2 injection pressures, temperatures, and crude oil compositions. The light-dead oil samples taken from two Indonesian oil fields were used. The impacts of the instability of crude oil on CO 2 displacement performance were also observed to evaluate oil recovery and minimum miscibility pressure (MMP). The observation was performed using a slim tube under varying CO 2 high-pressure injections at 90 °C and 70 °C. The produced oils were analyzed based on their polarity component, saturates, aromatics, resins, and asphaltenes fractions, to observe the changes in oil composition and colloidal index instability. The results showed that increasing temperatures at given pressures resulted in higher oil recovery. Moreover, the asphaltene and resin fractions in the oil produced at a lower temperature significantly decrease compared to those at a higher temperature. It was also shown that asphaltene tends to precipitate more easily at a lower temperature. The other phenomenon revealed that the lighter oil resulted in a lower recovery than the heavier oil at a given pressure and temperature and correspondingly higher MMP. It was also suggested that CO 2 flooding is more likely to cause asphaltene precipitation in light oils.
{"title":"The impacts of CO2 flooding on crude oil stability and recovery performance","authors":"Kartika F. Hartono, Asep K. Permadi, Ucok W. R. Siagian, Andri L. L. Hakim, Sumadi Paryoto, Ahlul H. Resha, Yudistira Adinugraha, Egi A. Pratama","doi":"10.1007/s13202-023-01699-y","DOIUrl":"https://doi.org/10.1007/s13202-023-01699-y","url":null,"abstract":"Abstract Numerous studies have investigated the fundamental mechanisms by which CO 2 flooding can increase oil production by altering the properties of the hydrocarbon fluid, including oil swelling, viscosity and interfacial tension reductions, and the extraction of light-to-intermediate components. However, the interactions between CO 2 and hydrocarbon fluid may also cause several problems, such as asphaltene precipitation due to crude oil's instability during the CO 2 flooding process. This study investigates the complex factors that affect the instability of crude oil, including CO 2 injection pressures, temperatures, and crude oil compositions. The light-dead oil samples taken from two Indonesian oil fields were used. The impacts of the instability of crude oil on CO 2 displacement performance were also observed to evaluate oil recovery and minimum miscibility pressure (MMP). The observation was performed using a slim tube under varying CO 2 high-pressure injections at 90 °C and 70 °C. The produced oils were analyzed based on their polarity component, saturates, aromatics, resins, and asphaltenes fractions, to observe the changes in oil composition and colloidal index instability. The results showed that increasing temperatures at given pressures resulted in higher oil recovery. Moreover, the asphaltene and resin fractions in the oil produced at a lower temperature significantly decrease compared to those at a higher temperature. It was also shown that asphaltene tends to precipitate more easily at a lower temperature. The other phenomenon revealed that the lighter oil resulted in a lower recovery than the heavier oil at a given pressure and temperature and correspondingly higher MMP. It was also suggested that CO 2 flooding is more likely to cause asphaltene precipitation in light oils.","PeriodicalId":16723,"journal":{"name":"Journal of Petroleum Exploration and Production Technology","volume":"358 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134912251","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-09-13DOI: 10.1007/s13202-023-01697-0
Okhiria D. Udebhulu, Yetunde Aladeitan, Ricardo C. Azevedo, Giorgio De Tomi
Abstract Cement sheath integrity is a critical concern in the successful implementation of geologic carbon capture and storage (CCS) projects. Conventional ordinary Portland cement (OPC) is not thermodynamically compatible with the carbon dioxide (CO 2 ) present in CO 2 storage media. When OPC cement sheaths interact with aqueous CO 2 , they undergo degradation, producing calcium bicarbonate. This bicarbonate readily dissolves in the formation aquifer and can create leakage pathways, compromising the integrity of the wellbores. This study comprehensively reviews the state-of-the-art techniques for evaluating cement sheath integrity, providing a comprehensive compendium of available methods in a single article. The paper’s objective is to support the deployment of successful CCS projects, facilitate the remediation of affected wellbores in CO 2 storage systems, and offer guidelines for evaluating improved cement slurry designs and formulations. Additionally, the study identifies the factors that influence cement sheath integrity when exposed to aqueous CO 2 , including in-situ temperature and pressure, reservoir fluid characteristics, cement slurry formulations, and wellbore operations. Furthermore, various modes of mechanical failure in cement sheaths are identified, such as radial cracking, plastic deformation, inner and outer debonding, and channeling. Understanding these failure mechanisms is crucial for designing robust cementing strategies in CCS applications. Evaluation techniques for assessing the integrity of cement sheaths exposed to aqueous CO 2 encompass a range of approaches. These include direct experimentation with samples that mimic the in -situ conditions of storage sites, well logging for monitoring leakages, analytical, numerical, and statistical modeling, and risk assessments. Direct experimentation plays a vital role in understanding the carbonation kinetics and changes in cement sheaths' mechanical and transport properties. Techniques such as scanning electron microscopy, back-scattered electron image detectors, energy-dispersive spectroscopy, mercury intrusion porosimetry, optical microscopy, X-ray diffraction, electrical resistivity imaging, electron probe microanalyzers, inductivity-coupled plasma optical emission spectrometry, X-ray computed microtomography, Raman spectroscopy, direct image correlation, and particle velocimetry are utilized for direct experimentation. Analytical and numerical modeling approaches include reactive transport modeling, multi-scale modeling, computational fluid dynamics (CFD), and artificial intelligence (AI)-based modeling. In field operations, the integrity of the cement sheaths can be evaluated using cement bond evaluation tools, pressure transient test tools, cement coring tools, or sustained casing pressure analysis. These techniques collectively enable a comprehensive assessment of the integrity of cement sheath exposed to aqueous CO 2 , aiding in optimizing and monitoring carbon storage
{"title":"A review of cement sheath integrity evaluation techniques for carbon dioxide storage","authors":"Okhiria D. Udebhulu, Yetunde Aladeitan, Ricardo C. Azevedo, Giorgio De Tomi","doi":"10.1007/s13202-023-01697-0","DOIUrl":"https://doi.org/10.1007/s13202-023-01697-0","url":null,"abstract":"Abstract Cement sheath integrity is a critical concern in the successful implementation of geologic carbon capture and storage (CCS) projects. Conventional ordinary Portland cement (OPC) is not thermodynamically compatible with the carbon dioxide (CO 2 ) present in CO 2 storage media. When OPC cement sheaths interact with aqueous CO 2 , they undergo degradation, producing calcium bicarbonate. This bicarbonate readily dissolves in the formation aquifer and can create leakage pathways, compromising the integrity of the wellbores. This study comprehensively reviews the state-of-the-art techniques for evaluating cement sheath integrity, providing a comprehensive compendium of available methods in a single article. The paper’s objective is to support the deployment of successful CCS projects, facilitate the remediation of affected wellbores in CO 2 storage systems, and offer guidelines for evaluating improved cement slurry designs and formulations. Additionally, the study identifies the factors that influence cement sheath integrity when exposed to aqueous CO 2 , including in-situ temperature and pressure, reservoir fluid characteristics, cement slurry formulations, and wellbore operations. Furthermore, various modes of mechanical failure in cement sheaths are identified, such as radial cracking, plastic deformation, inner and outer debonding, and channeling. Understanding these failure mechanisms is crucial for designing robust cementing strategies in CCS applications. Evaluation techniques for assessing the integrity of cement sheaths exposed to aqueous CO 2 encompass a range of approaches. These include direct experimentation with samples that mimic the in -situ conditions of storage sites, well logging for monitoring leakages, analytical, numerical, and statistical modeling, and risk assessments. Direct experimentation plays a vital role in understanding the carbonation kinetics and changes in cement sheaths' mechanical and transport properties. Techniques such as scanning electron microscopy, back-scattered electron image detectors, energy-dispersive spectroscopy, mercury intrusion porosimetry, optical microscopy, X-ray diffraction, electrical resistivity imaging, electron probe microanalyzers, inductivity-coupled plasma optical emission spectrometry, X-ray computed microtomography, Raman spectroscopy, direct image correlation, and particle velocimetry are utilized for direct experimentation. Analytical and numerical modeling approaches include reactive transport modeling, multi-scale modeling, computational fluid dynamics (CFD), and artificial intelligence (AI)-based modeling. In field operations, the integrity of the cement sheaths can be evaluated using cement bond evaluation tools, pressure transient test tools, cement coring tools, or sustained casing pressure analysis. These techniques collectively enable a comprehensive assessment of the integrity of cement sheath exposed to aqueous CO 2 , aiding in optimizing and monitoring carbon storage","PeriodicalId":16723,"journal":{"name":"Journal of Petroleum Exploration and Production Technology","volume":"40 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135787552","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-09-12DOI: 10.1007/s13202-023-01694-3
Ahmed Farid Ibrahim, Ruud Weijermars
Abstract Accurate estimation of fracture half-lengths in shale gas and oil reservoirs is critical for optimizing stimulation design, evaluating production potential, monitoring reservoir performance, and making informed economic decisions. Assessing the dimensions of hydraulic fractures and the quality of well completions in shale gas and oil reservoirs typically involves techniques such as chemical tracers, microseismic fiber optics, and production logs, which can be time-consuming and costly. This study demonstrates an alternative approach to estimate fracture half-lengths using the Gaussian pressure transient (GPT) Method, which has recently emerged as a novel technique for quantifying pressure depletion around single wells, multiple wells, and hydraulic fractures. The GPT method is compared to the well-established rate transient analysis (RTA) method to evaluate its effectiveness in estimating fracture parameters. The study used production data from 11 wells at the hydraulic fracture test site 1 in the Midland Basin of West Texas from Upper and Middle Wolfcamp (WC) formations. The data included flow rates and pressure readings, and the fracture half-lengths of the 11 wells were individually estimated by matching the production data to historical records. The GPT method can calculate the fracture half-length from daily production data, given a certain formation permeability. Independently, the traditional RTA method was applied to separately estimate the fracture half-length. The results of the two methods (GPT and RTA) are within an acceptable, small error margin for all 5 of the Middle WC wells studied, and for 5 of the 6 Upper WC wells. The slight deviation in the case of the Upper WC well is due to the different production control and a longer time for the well to reach constant bottomhole pressure. The estimated stimulated surface area for the Middle and Upper WC wells was correlated to the injected proppant volume and the total fluid production. Applying RTA and GPT methods to the historic production data improves the fracture diagnostics accuracy by reducing the uncertainty in the estimation of fracture dimensions, for given formation permeability values of the stimulated rock volume.
{"title":"Estimation of fracture half-length with fast Gaussian pressure transient and RTA methods: Wolfcamp shale formation case study","authors":"Ahmed Farid Ibrahim, Ruud Weijermars","doi":"10.1007/s13202-023-01694-3","DOIUrl":"https://doi.org/10.1007/s13202-023-01694-3","url":null,"abstract":"Abstract Accurate estimation of fracture half-lengths in shale gas and oil reservoirs is critical for optimizing stimulation design, evaluating production potential, monitoring reservoir performance, and making informed economic decisions. Assessing the dimensions of hydraulic fractures and the quality of well completions in shale gas and oil reservoirs typically involves techniques such as chemical tracers, microseismic fiber optics, and production logs, which can be time-consuming and costly. This study demonstrates an alternative approach to estimate fracture half-lengths using the Gaussian pressure transient (GPT) Method, which has recently emerged as a novel technique for quantifying pressure depletion around single wells, multiple wells, and hydraulic fractures. The GPT method is compared to the well-established rate transient analysis (RTA) method to evaluate its effectiveness in estimating fracture parameters. The study used production data from 11 wells at the hydraulic fracture test site 1 in the Midland Basin of West Texas from Upper and Middle Wolfcamp (WC) formations. The data included flow rates and pressure readings, and the fracture half-lengths of the 11 wells were individually estimated by matching the production data to historical records. The GPT method can calculate the fracture half-length from daily production data, given a certain formation permeability. Independently, the traditional RTA method was applied to separately estimate the fracture half-length. The results of the two methods (GPT and RTA) are within an acceptable, small error margin for all 5 of the Middle WC wells studied, and for 5 of the 6 Upper WC wells. The slight deviation in the case of the Upper WC well is due to the different production control and a longer time for the well to reach constant bottomhole pressure. The estimated stimulated surface area for the Middle and Upper WC wells was correlated to the injected proppant volume and the total fluid production. Applying RTA and GPT methods to the historic production data improves the fracture diagnostics accuracy by reducing the uncertainty in the estimation of fracture dimensions, for given formation permeability values of the stimulated rock volume.","PeriodicalId":16723,"journal":{"name":"Journal of Petroleum Exploration and Production Technology","volume":"134 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135878050","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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