Lei Zhang, Jun Ni, Chengjun Wang, Chengyong Li, Kai Cui
To promote the effect of waterflooding of a heterogeneous low-permeability reservoir in the Ordos Basin, a microbial plugging agent is developed to plug the multiscale water channeling. Based on the characteristics of the growth of bacteria, the microbial plugging agent can plug both porous media and microfractures with different scales. The microbial plugging agent is prepared by activating the native bacteria present in low-permeability reservoirs by using the fermentation nutrients. After growing in the fermentation nutrient solution for 4 days in a beaker, the growth of microbial strains begins to stabilize. After that, the main particle size of the prepared microbial plugging agent is between 40 μm and 160 μm and the median particle size (D50) is near 90 μm. The microbial plugging agent has good shear resistance, salt resistance, and stability. At the initial state, due to good injectivity, the microbial plugging agent can smoothly enter into a low-permeability core, a heterogeneous core, and a fractured core, respectively. Thus, it can grow and reproduce in the cores. Based on the characteristics of growth, it can match with the spatial scale of pore or fracture in the cores, so that it cannot only plug the porous media water channeling with different scales but also plug the microfracture water channeling with different scales. This phenomenon has been confirmed by microscopic visualization flow experiments and core flow experiments. The developed microbial plugging agent can be applied to plug the multiscale water channeling to enhance oil recovery of low-permeability heterogeneous reservoirs.
{"title":"Study on Plugging the Multiscale Water Channeling in Low-Permeability Heterogeneous Porous Media Based on the Growth of Bacteria","authors":"Lei Zhang, Jun Ni, Chengjun Wang, Chengyong Li, Kai Cui","doi":"10.2118/219768-pa","DOIUrl":"https://doi.org/10.2118/219768-pa","url":null,"abstract":"\u0000 To promote the effect of waterflooding of a heterogeneous low-permeability reservoir in the Ordos Basin, a microbial plugging agent is developed to plug the multiscale water channeling. Based on the characteristics of the growth of bacteria, the microbial plugging agent can plug both porous media and microfractures with different scales. The microbial plugging agent is prepared by activating the native bacteria present in low-permeability reservoirs by using the fermentation nutrients. After growing in the fermentation nutrient solution for 4 days in a beaker, the growth of microbial strains begins to stabilize. After that, the main particle size of the prepared microbial plugging agent is between 40 μm and 160 μm and the median particle size (D50) is near 90 μm. The microbial plugging agent has good shear resistance, salt resistance, and stability. At the initial state, due to good injectivity, the microbial plugging agent can smoothly enter into a low-permeability core, a heterogeneous core, and a fractured core, respectively. Thus, it can grow and reproduce in the cores. Based on the characteristics of growth, it can match with the spatial scale of pore or fracture in the cores, so that it cannot only plug the porous media water channeling with different scales but also plug the microfracture water channeling with different scales. This phenomenon has been confirmed by microscopic visualization flow experiments and core flow experiments. The developed microbial plugging agent can be applied to plug the multiscale water channeling to enhance oil recovery of low-permeability heterogeneous reservoirs.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141042440","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Qihang Shen, Jian Liu, Zaoyuan Li, Sheng Huang, Xuning Wu, Jinfei Sun, D. Su, Jin Li
At present, lost circulation remains a complicated drilling problem in fractured formations that needs to be addressed urgently. However, the influence of actual rock mechanical properties (RMP) and fracture morphological features (FMF) on lost circulation is easily ignored in the current research on leakage mechanism and evaluation, which may lead to deviation from the analysis results, thus affecting the success rate of plugging treatments. Therefore, the complicated effects have been investigated using the improved plugging experimental instruments in this paper. The results indicate that both RMP and FMF have a prominent influence on the plugging and sealing effects of plugging slurries. This research suggests that the bridging and plugging capabilities of the slurry can be improved by increasing the type and amount of lost circulation materials (LCM). Moreover, depending on the fracture morphology difference, the same plugging slurry will have different plugging effects on the same width-size opening fracture channel. In addition, a novel evaluation method is developed to assess the effective sealing ability of plugging slurry against formation fractures, which has been successfully applied in the field. To the best of our knowledge, this is the first evaluation method that investigates simultaneously the mechanical properties of rocks and fracture characteristics of formations. The novel evaluation method incorporates the critical parameters of the lost circulation effect into the design of the plugging evaluation model. Thus, the proposed method can be used to quantitatively evaluate the plugging capability of the LCM and slurries and the loss capacity of the loss channels. However, the higher plugging coefficient (λ) of the slurry does not necessarily mean that the plugging slurry has a stronger plugging capacity (SP). Adopting the suitable fracture channel model can avoid overestimating or underestimating the plugging capability of the LCM slurries. Therefore, it is necessary to improve the formula design of the LCM slurry in combination with the geological engineering background. This perception has significant implications for the analysis of the lost circulation mechanisms and the optimization formula design of the plugging slurries.
{"title":"Experimental Study on the Effect of Rock Mechanical Properties and Fracture Morphology Features on Lost Circulation","authors":"Qihang Shen, Jian Liu, Zaoyuan Li, Sheng Huang, Xuning Wu, Jinfei Sun, D. Su, Jin Li","doi":"10.2118/219765-pa","DOIUrl":"https://doi.org/10.2118/219765-pa","url":null,"abstract":"\u0000 At present, lost circulation remains a complicated drilling problem in fractured formations that needs to be addressed urgently. However, the influence of actual rock mechanical properties (RMP) and fracture morphological features (FMF) on lost circulation is easily ignored in the current research on leakage mechanism and evaluation, which may lead to deviation from the analysis results, thus affecting the success rate of plugging treatments. Therefore, the complicated effects have been investigated using the improved plugging experimental instruments in this paper. The results indicate that both RMP and FMF have a prominent influence on the plugging and sealing effects of plugging slurries. This research suggests that the bridging and plugging capabilities of the slurry can be improved by increasing the type and amount of lost circulation materials (LCM). Moreover, depending on the fracture morphology difference, the same plugging slurry will have different plugging effects on the same width-size opening fracture channel. In addition, a novel evaluation method is developed to assess the effective sealing ability of plugging slurry against formation fractures, which has been successfully applied in the field. To the best of our knowledge, this is the first evaluation method that investigates simultaneously the mechanical properties of rocks and fracture characteristics of formations. The novel evaluation method incorporates the critical parameters of the lost circulation effect into the design of the plugging evaluation model. Thus, the proposed method can be used to quantitatively evaluate the plugging capability of the LCM and slurries and the loss capacity of the loss channels. However, the higher plugging coefficient (λ) of the slurry does not necessarily mean that the plugging slurry has a stronger plugging capacity (SP). Adopting the suitable fracture channel model can avoid overestimating or underestimating the plugging capability of the LCM slurries. Therefore, it is necessary to improve the formula design of the LCM slurry in combination with the geological engineering background. This perception has significant implications for the analysis of the lost circulation mechanisms and the optimization formula design of the plugging slurries.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141029142","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
To address the problems of steam channeling caused by the nonhomogeneity and fluid compatibility of the reservoir in heavy oil reservoirs and the permanent damage to the reservoir easily caused by traditional plugging agents, this study adopted polyaluminum chloride (PAC) as the main agent, urea as the coagulant promoter, and thiourea as the stabilizer and prepared a high-temperature-resistant (up to 350°C) degradable inorganic aluminum gel with excellent performance. Initially, scanning electron microscope (SEM) tests were conducted on gels with and without urea. Energy-dispersive X-ray spectroscopy (EDS)-mapping analysis of gels immersed in water with different mineralization levels for 5 days was then performed. The results revealed that the addition of urea led to a tighter and more complete crosslinked structure, significantly enhancing the mechanical strength of the gel. As water mineral content increased, the gel’s microstructure became denser and smoother. Metal cations on the cross-sectional surface increased gradually and distributed uniformly, further confirming the mechanism of the synergistic salt effect of soluble strong electrolytes and urea in strengthening the gel. Finally, the plugging and degradable properties of the gel were evaluated, and the results showed that the plugging percentage of the gel could still reach 97.6% after aging at 350°C for 30 days, and the gel had excellent plugging and diversion in dual sandpack experiments where the permeability ratio was less than 44. At 250°C, the degradation percentage of the gel was more than 98% at 5 days under the nonacid degradation system and 94% at 5 days under the acid degradation system. The gel showed good degradability and effectively reduced the damage to the reservoir.
{"title":"Preparation and Performance of High-Temperature-Resistant, Degradable Inorganic Gel for Steam Applications","authors":"Lifeng Chen, Zhaonian Zhang, Huiyong Zeng, Feiyang Huang, Xuanfeng Lu, Weiwei Sheng","doi":"10.2118/219775-pa","DOIUrl":"https://doi.org/10.2118/219775-pa","url":null,"abstract":"\u0000 To address the problems of steam channeling caused by the nonhomogeneity and fluid compatibility of the reservoir in heavy oil reservoirs and the permanent damage to the reservoir easily caused by traditional plugging agents, this study adopted polyaluminum chloride (PAC) as the main agent, urea as the coagulant promoter, and thiourea as the stabilizer and prepared a high-temperature-resistant (up to 350°C) degradable inorganic aluminum gel with excellent performance. Initially, scanning electron microscope (SEM) tests were conducted on gels with and without urea. Energy-dispersive X-ray spectroscopy (EDS)-mapping analysis of gels immersed in water with different mineralization levels for 5 days was then performed. The results revealed that the addition of urea led to a tighter and more complete crosslinked structure, significantly enhancing the mechanical strength of the gel. As water mineral content increased, the gel’s microstructure became denser and smoother. Metal cations on the cross-sectional surface increased gradually and distributed uniformly, further confirming the mechanism of the synergistic salt effect of soluble strong electrolytes and urea in strengthening the gel. Finally, the plugging and degradable properties of the gel were evaluated, and the results showed that the plugging percentage of the gel could still reach 97.6% after aging at 350°C for 30 days, and the gel had excellent plugging and diversion in dual sandpack experiments where the permeability ratio was less than 44. At 250°C, the degradation percentage of the gel was more than 98% at 5 days under the nonacid degradation system and 94% at 5 days under the acid degradation system. The gel showed good degradability and effectively reduced the damage to the reservoir.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141131720","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Nuclear magnetic resonance (NMR) logging is effective for reservoir evaluation; at present, NMR logging data acquisition parameters are primarily divided into dual wait time (TW) and dual echo time (TE) and then are analyzed, respectively. However, the interpretation results of the two activations are often inconsistent and confuse the identification and quantitative evaluation of reservoir fluids. Based on the principle of multi-TW and -TE activations of NMR logging, the relaxation mechanism is analyzed, and the relationship between the amplitude of the echo train and the pore structure, fluid types, and content of different activations is established. The joint system of the amplitude of echo trains in multiactivations is constructed. Then, the difference spectrum and the oil porosity of the flushed zone can be calculated by the least squares algorithm (LSQR). The fluid-saturated rock model is set, and the numerical simulation of NMR is used to verify the data joint inversion is correct and that the calculation result is more accurate than the previous time domain analysis (TDA) processing method. Moreover, the oil porosity of the flushed zone-deep induction resistivity crossplot is constructed and is also proposed to identify fluid. The above method was applied to the Yanchang Formation in the western Ordos Basin. Based on the joint inversion of NMR multi-TW and -TE logging data in the study area, the methodology yields more precise calculations of fluid volume and saturation compared with conventional approaches. The crossplots derived from these calculations demonstrate high efficacy in identifying fluid types; therefore, the method for fluid identification exhibits potential for practical application and holds considerable value for widespread adoption in the field.
{"title":"Joint Inversion Method of Nuclear Magnetic Resonance Logging Multiwait Time and Multiecho Time Activation Data and Fluid Identification","authors":"Bo Li, Maojin Tan, Haitao Zhang, Jinyu Zhou, Changsheng Wang, Haopeng Guo","doi":"10.2118/221452-pa","DOIUrl":"https://doi.org/10.2118/221452-pa","url":null,"abstract":"\u0000 Nuclear magnetic resonance (NMR) logging is effective for reservoir evaluation; at present, NMR logging data acquisition parameters are primarily divided into dual wait time (TW) and dual echo time (TE) and then are analyzed, respectively. However, the interpretation results of the two activations are often inconsistent and confuse the identification and quantitative evaluation of reservoir fluids. Based on the principle of multi-TW and -TE activations of NMR logging, the relaxation mechanism is analyzed, and the relationship between the amplitude of the echo train and the pore structure, fluid types, and content of different activations is established. The joint system of the amplitude of echo trains in multiactivations is constructed. Then, the difference spectrum and the oil porosity of the flushed zone can be calculated by the least squares algorithm (LSQR). The fluid-saturated rock model is set, and the numerical simulation of NMR is used to verify the data joint inversion is correct and that the calculation result is more accurate than the previous time domain analysis (TDA) processing method. Moreover, the oil porosity of the flushed zone-deep induction resistivity crossplot is constructed and is also proposed to identify fluid. The above method was applied to the Yanchang Formation in the western Ordos Basin. Based on the joint inversion of NMR multi-TW and -TE logging data in the study area, the methodology yields more precise calculations of fluid volume and saturation compared with conventional approaches. The crossplots derived from these calculations demonstrate high efficacy in identifying fluid types; therefore, the method for fluid identification exhibits potential for practical application and holds considerable value for widespread adoption in the field.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141131763","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Understanding how pressure propagates in a reservoir is fundamental to the interpretation of pressure and rate transient measurements at a well. Unconventional reservoirs provide unique technical challenges as the simple geometries and flow regimes [wellbore storage (WBS) and radial, linear, spherical, and boundary-dominated flow] applied in well test analysis are now replaced by nonideal flow patterns due to complex multistage fracture completions, nonplanar fractures, and the interaction of flow with the reservoir heterogeneity. In this paper, we introduce an asymptotic solution technique for the diffusivity equation applied to pressure transient analysis (PTA), in which the 3D depletion geometry is mapped to an equivalent 1D streamtube. This allows the potentially complex pressure depletion geometry within the reservoir to be treated as the primary unknown in an interpretation, compared with the usual method of interpretation in which the depletion geometry is assumed and parameters of the formation and well are the unknown properties. The construction is based upon the solution to the Eikonal equation, derived from the diffusivity equation in heterogeneous reservoirs. We develop a Green’s function that provides analytic solutions to the pressure transient equations for which the geometry of the flow pattern is abstracted from the transient solution. The analytic formulation provides an explicit solution for many well test pressure transient characteristics such as the well test semi-log pressure derivative (WTD), the depth of investigation (DOI), and the stabilized zone (SZ) (or dynamic drainage area), with new definitions for the limit of detectability (LOD), the transient drainage volume, and the pseudosteady-state (PSS) limit. Generalizations of the Green’s function approach to bounded reservoirs are possible (Wang et al. 2017) but are beyond the scope of the current study. We validate our approach against well-known PTA solutions solved using the Laplace transform, including pressure transients with WBS and skin. Our study concludes with a discussion of applications to unconventional reservoir performance analysis for which reference solutions do not otherwise exist.
{"title":"Applications of Asymptotic Solutions of the Diffusivity Equation to Infinite Acting Pressure Transient Analysis","authors":"Zhenzhen Wang, Chen Li, Michael J. King","doi":"10.2118/180149-pa","DOIUrl":"https://doi.org/10.2118/180149-pa","url":null,"abstract":"\u0000 Understanding how pressure propagates in a reservoir is fundamental to the interpretation of pressure and rate transient measurements at a well. Unconventional reservoirs provide unique technical challenges as the simple geometries and flow regimes [wellbore storage (WBS) and radial, linear, spherical, and boundary-dominated flow] applied in well test analysis are now replaced by nonideal flow patterns due to complex multistage fracture completions, nonplanar fractures, and the interaction of flow with the reservoir heterogeneity. In this paper, we introduce an asymptotic solution technique for the diffusivity equation applied to pressure transient analysis (PTA), in which the 3D depletion geometry is mapped to an equivalent 1D streamtube. This allows the potentially complex pressure depletion geometry within the reservoir to be treated as the primary unknown in an interpretation, compared with the usual method of interpretation in which the depletion geometry is assumed and parameters of the formation and well are the unknown properties. The construction is based upon the solution to the Eikonal equation, derived from the diffusivity equation in heterogeneous reservoirs. We develop a Green’s function that provides analytic solutions to the pressure transient equations for which the geometry of the flow pattern is abstracted from the transient solution. The analytic formulation provides an explicit solution for many well test pressure transient characteristics such as the well test semi-log pressure derivative (WTD), the depth of investigation (DOI), and the stabilized zone (SZ) (or dynamic drainage area), with new definitions for the limit of detectability (LOD), the transient drainage volume, and the pseudosteady-state (PSS) limit. Generalizations of the Green’s function approach to bounded reservoirs are possible (Wang et al. 2017) but are beyond the scope of the current study. We validate our approach against well-known PTA solutions solved using the Laplace transform, including pressure transients with WBS and skin. Our study concludes with a discussion of applications to unconventional reservoir performance analysis for which reference solutions do not otherwise exist.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141142402","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Shale reservoirs have longitudinally developed multilayered weak surfaces. The strong geological discontinuity and the stress heterogeneity caused by it lead to the complicated morphology of hydraulic fracture propagation, and the longitudinal propagation mechanism of the hydraulic fracture is still unclear. The extended finite element 3D numerical model of the single-cluster fracture and multicluster fracture extension has been established. The effects of vertical stress difference, bonding strength of bedding plane, fracturing fluid displacement, fracturing fluid viscosity, and cluster spacing on fracture propagation morphology are analyzed by numerical examples. The results show that as the vertical stress difference and the bonding strength of the bedding plane increase, the bedding plane becomes more difficult to activate, and the fractures are more likely to realize the longitudinal penetration. As the cluster spacing decreases, the interfracture interference becomes stronger, and the hydraulic fractures are more likely to activate the bedding plane and form the orthogonal network fracture. At a high injection rate, the fracture passes easily through the layer and activates the bedding plane. Low-viscosity fracturing fluid is conducive to the activation of the bedding plane, and high-viscosity fracturing fluid can better achieve fracture penetration. Based on the research results, the fracturing parameters of Well X-1 are optimized, and the fracture monitoring results are in good agreement with the design objectives. This study reveals the longitudinal penetration mechanism of multilayered shale hydraulic fractures and provides a reference for the optimization of hydraulic fracturing parameters of multilayered shale.
{"title":"Study on the Mechanism and Regulation Method of Longitudinal Penetration of Hydraulic Fractures in Multilayered Shale","authors":"Jianbin Li, Zhifeng Luo, Nanlin Zhang, Xiuquan Zeng, Yucheng Jia","doi":"10.2118/221450-pa","DOIUrl":"https://doi.org/10.2118/221450-pa","url":null,"abstract":"\u0000 Shale reservoirs have longitudinally developed multilayered weak surfaces. The strong geological discontinuity and the stress heterogeneity caused by it lead to the complicated morphology of hydraulic fracture propagation, and the longitudinal propagation mechanism of the hydraulic fracture is still unclear. The extended finite element 3D numerical model of the single-cluster fracture and multicluster fracture extension has been established. The effects of vertical stress difference, bonding strength of bedding plane, fracturing fluid displacement, fracturing fluid viscosity, and cluster spacing on fracture propagation morphology are analyzed by numerical examples. The results show that as the vertical stress difference and the bonding strength of the bedding plane increase, the bedding plane becomes more difficult to activate, and the fractures are more likely to realize the longitudinal penetration. As the cluster spacing decreases, the interfracture interference becomes stronger, and the hydraulic fractures are more likely to activate the bedding plane and form the orthogonal network fracture. At a high injection rate, the fracture passes easily through the layer and activates the bedding plane. Low-viscosity fracturing fluid is conducive to the activation of the bedding plane, and high-viscosity fracturing fluid can better achieve fracture penetration. Based on the research results, the fracturing parameters of Well X-1 are optimized, and the fracture monitoring results are in good agreement with the design objectives. This study reveals the longitudinal penetration mechanism of multilayered shale hydraulic fractures and provides a reference for the optimization of hydraulic fracturing parameters of multilayered shale.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141139975","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Diabate, Fatemeh Kalantari, Steven Chen, Jian Shi, H. Krishnamoorthy
Carbon dioxide (CO2) occupies the leading position among greenhouse gas (GHG) emissions that adversely impact the environment. A way to remedy the growing emission of CO2 is by using carbon capture and storage (CCS) or carbon capture, utilization, and storage (CCUS) technologies. This paper proposes a novel optimization framework to minimize the transportation cost of CO2 by determining the required number of booster pumps, with the consideration of the impact of pipeline length and CO2 flow rate. As a case study, we conducted a study of optimally transporting 1 Mt (million tonnes) of CO2 through pipelines from four well-defined sources over 62 miles (sink) in the greater Houston area (Texas, USA). This optimization problem considers the impact of pipeline length and CO2 flow rate on the transportation cost of CO2. The results from the optimized system show that the pipeline length and CO2 flow rate need to be tuned properly to optimally transport and recover the investment price. For the system to be cost-effective, it is preferable to transport a high flow rate of CO2 (>50 Mt) over a longer distance (>100 miles); anything outside the mentioned ranges or less can increase the investment and CO2 transportation costs.
{"title":"Analyzing the Impact of Pipeline Length and CO2 Mass Flow Rate on the Transportation Cost Based on the Required Number of Booster Pumps: A Case Study of Houston","authors":"M. Diabate, Fatemeh Kalantari, Steven Chen, Jian Shi, H. Krishnamoorthy","doi":"10.2118/219729-pa","DOIUrl":"https://doi.org/10.2118/219729-pa","url":null,"abstract":"\u0000 Carbon dioxide (CO2) occupies the leading position among greenhouse gas (GHG) emissions that adversely impact the environment. A way to remedy the growing emission of CO2 is by using carbon capture and storage (CCS) or carbon capture, utilization, and storage (CCUS) technologies. This paper proposes a novel optimization framework to minimize the transportation cost of CO2 by determining the required number of booster pumps, with the consideration of the impact of pipeline length and CO2 flow rate. As a case study, we conducted a study of optimally transporting 1 Mt (million tonnes) of CO2 through pipelines from four well-defined sources over 62 miles (sink) in the greater Houston area (Texas, USA). This optimization problem considers the impact of pipeline length and CO2 flow rate on the transportation cost of CO2. The results from the optimized system show that the pipeline length and CO2 flow rate need to be tuned properly to optimally transport and recover the investment price. For the system to be cost-effective, it is preferable to transport a high flow rate of CO2 (>50 Mt) over a longer distance (>100 miles); anything outside the mentioned ranges or less can increase the investment and CO2 transportation costs.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140777030","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Nuclear magnetic resonance (NMR) logging has been extensively utilized for identifying pore fluids in recent years. However, after oil-based mud (OBM) invasion, OBM filtrate partially takes the place of the original fluid in the reservoir and the morphology of the NMR T2 (transverse relaxation time) spectrum changes. OBM invasion makes it difficult to identify the formation fluid using routine NMR fluid identification methods. In this study, we took heterogeneous conglomerate formation in the northwestern Junggar Basin as a case study and carried out core experiments under four conditions (viz., water-saturated, OBM displacing water, oil-saturated, and OBM displacing oil) and simulated the states of OBM invasion into water and hydrocarbon-bearing formation. Comparative analysis finds that when the OBM invades the water layer, the movable peak of the T2 spectrum primarily reflects the bulk relaxation characteristics of OBM filtrate, whereas when the OBM invades into the oil layer, the T2 spectrum may exhibit a three-peak distribution, where the first peak mainly indicates irreducible water, the second peak reflects OBM filtrate, and the third peak primarily reflects nondisplaced oil. To facilitate fluid identification, two T2 cutoffs are adopted to divide the T2 spectrum into three segments, and combined with the T2 geometric average, a fluid identification factor (ifluid) is proposed. Finally, identification criteria for reservoir type are established on the NMR logging and drillstem test data. The field application verifies the reliability of the proposed methods. These methods realize the identification of oil layers under OBM drilling and guide the subsequent production and development of oil reservoirs.
{"title":"A Method to Identify Pore Fluids in Heterogeneous Conglomerate Reservoirs Using a Nuclear Magnetic Resonance Log with Oil-Based Mud Invasion","authors":"Feiming Gao, Liang Xiao","doi":"10.2118/219764-pa","DOIUrl":"https://doi.org/10.2118/219764-pa","url":null,"abstract":"\u0000 Nuclear magnetic resonance (NMR) logging has been extensively utilized for identifying pore fluids in recent years. However, after oil-based mud (OBM) invasion, OBM filtrate partially takes the place of the original fluid in the reservoir and the morphology of the NMR T2 (transverse relaxation time) spectrum changes. OBM invasion makes it difficult to identify the formation fluid using routine NMR fluid identification methods. In this study, we took heterogeneous conglomerate formation in the northwestern Junggar Basin as a case study and carried out core experiments under four conditions (viz., water-saturated, OBM displacing water, oil-saturated, and OBM displacing oil) and simulated the states of OBM invasion into water and hydrocarbon-bearing formation. Comparative analysis finds that when the OBM invades the water layer, the movable peak of the T2 spectrum primarily reflects the bulk relaxation characteristics of OBM filtrate, whereas when the OBM invades into the oil layer, the T2 spectrum may exhibit a three-peak distribution, where the first peak mainly indicates irreducible water, the second peak reflects OBM filtrate, and the third peak primarily reflects nondisplaced oil. To facilitate fluid identification, two T2 cutoffs are adopted to divide the T2 spectrum into three segments, and combined with the T2 geometric average, a fluid identification factor (ifluid) is proposed. Finally, identification criteria for reservoir type are established on the NMR logging and drillstem test data. The field application verifies the reliability of the proposed methods. These methods realize the identification of oil layers under OBM drilling and guide the subsequent production and development of oil reservoirs.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140788283","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Maye Beldongar, B. Gadiyar, J. Jeanpert, Kevin Whaley, Philip Jackson, Gabriele Carpineta, Salvatore Luppina, Lisa Farina, Michele Giammancheri
In openhole completions, screens are one of the very common equipment used to control production of solids. Screens could get plugged during installation in case of improper wellbore fluid conditioning and displacement. Awareness of screen plugging is not widely spread, and many practicing engineers do not pay enough attention to its implications. In this paper, we discuss the causes, consequences, and ways of determining plugging and recommend best practices to reduce the risk of screen plugging. First, we review the various reasons for screens to get plugged during openhole completion installations and explain in detail undesirable events caused by screen plugging such as: Inability to properly displace wellbore fluids Inability to fully pack the screen annulus Damage to screens during displacement and gravel packing We also review downhole gauge data of several jobs to identify and discuss screen plugging signatures and their outcomes. Additionally, we discuss potential preventive measures. In openhole completions, it is very common to run screens in wellbores containing solids-laden fluids intentionally or unintentionally. Poor wellbore displacement or improper fluid conditioning can result in leaving some bigger size solids in the screen-running fluid (SRF), which could plug the screens. Also, the exposure of reactive shales to water-based fluids can destabilize the shales and lead to plugging. In some cases, the SRF quality control is not properly accounting for the actual flow inside the screen while running in hole, resulting in a false pass. We present several case histories of downhole gauge data analysis, showing evidence of screen plugging leading to excessive treating pressure, incomplete gravel pack, and, in a few cases, screen erosion during gravel pack operations. To prevent screen plugging, it is necessary to properly model all the displacement stages, pay attention to proper conditioning and quality control of the fluid, and ensure compatibility of the fluids with shales. A comprehensive review of screen plugging during sand control installation phase and its potential consequences supported with extensive downhole gauge data has not been published previously. This paper will be a valuable source of knowledge for completion engineers and help them better design and execute future operations.
{"title":"A Comprehensive Review of Screen Plugging during Openhole Sand Control Completions Installation: Causes, Consequences, and Best Practices","authors":"Maye Beldongar, B. Gadiyar, J. Jeanpert, Kevin Whaley, Philip Jackson, Gabriele Carpineta, Salvatore Luppina, Lisa Farina, Michele Giammancheri","doi":"10.2118/215070-pa","DOIUrl":"https://doi.org/10.2118/215070-pa","url":null,"abstract":"\u0000 In openhole completions, screens are one of the very common equipment used to control production of solids. Screens could get plugged during installation in case of improper wellbore fluid conditioning and displacement. Awareness of screen plugging is not widely spread, and many practicing engineers do not pay enough attention to its implications. In this paper, we discuss the causes, consequences, and ways of determining plugging and recommend best practices to reduce the risk of screen plugging.\u0000 First, we review the various reasons for screens to get plugged during openhole completion installations and explain in detail undesirable events caused by screen plugging such as:\u0000 Inability to properly displace wellbore fluids Inability to fully pack the screen annulus Damage to screens during displacement and gravel packing\u0000 We also review downhole gauge data of several jobs to identify and discuss screen plugging signatures and their outcomes. Additionally, we discuss potential preventive measures.\u0000 In openhole completions, it is very common to run screens in wellbores containing solids-laden fluids intentionally or unintentionally. Poor wellbore displacement or improper fluid conditioning can result in leaving some bigger size solids in the screen-running fluid (SRF), which could plug the screens. Also, the exposure of reactive shales to water-based fluids can destabilize the shales and lead to plugging. In some cases, the SRF quality control is not properly accounting for the actual flow inside the screen while running in hole, resulting in a false pass.\u0000 We present several case histories of downhole gauge data analysis, showing evidence of screen plugging leading to excessive treating pressure, incomplete gravel pack, and, in a few cases, screen erosion during gravel pack operations. To prevent screen plugging, it is necessary to properly model all the displacement stages, pay attention to proper conditioning and quality control of the fluid, and ensure compatibility of the fluids with shales.\u0000 A comprehensive review of screen plugging during sand control installation phase and its potential consequences supported with extensive downhole gauge data has not been published previously. This paper will be a valuable source of knowledge for completion engineers and help them better design and execute future operations.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140781699","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
During the drilling of long horizontal wells, the significant frictional resistance generated by the wellbore walls poses a challenge for the drillstring to efficiently transmit load to the drill bit, which eventually reduces drilling efficiency and restricts the extension distance achievable. Inspired by the structure and movement principle of an earthworm, we propose an earthworm-like load transfer method for the drillstring to address this issue. Specifically, the proposed method involves the installation of a pulse generator and multiple vibration subs within the same drillstring, decomposes the drillstring into multiple sections and modulates it to creep like an earthworm, thus facilitating load transfer. Experimental studies and numerical simulations were conducted in this paper to explore the fundamental mechanisms of earthworm-like crawling, aiming to enhance the efficiency of load transfer within the drillstring. The experimental results suggest that adopting earthworm-like excitation can increase the load transfer efficiency of the drillstring by 36–52% compared to conventional drilling methods. However, if the drillstring experiences helical buckling, there is a significant decrease in the efficiency of load transfer. Meanwhile, a dynamic model of the drillstring, considering the 3D wellbore trajectory, multipoint excitation, Stribeck friction, and penetration rate, has been developed. The simulated results from the proposed model align well with the experimental results obtained before the drillstring buckling, with an error of less than 5%. The simulation results for a 1000-m drillstring indicate that the earthworm-like excitation significantly enhances the efficiency of load transfer compared to conventional drilling methods. This improvement is attributed to the increase in the proportion of reverse-motion drillstring segments by 35.8–40.25%, which will greatly reduce the instantaneous total vector frictional force of the entire drillstring.
{"title":"Axial Load Peristaltic Transfer Mechanism of the Drillstring to Improve Penetration Rate","authors":"Peng Wang, Jifei Cao, Heng Zhang, Weimin Yue, Hongjian Ni, Rui Zhang","doi":"10.2118/219737-pa","DOIUrl":"https://doi.org/10.2118/219737-pa","url":null,"abstract":"\u0000 During the drilling of long horizontal wells, the significant frictional resistance generated by the wellbore walls poses a challenge for the drillstring to efficiently transmit load to the drill bit, which eventually reduces drilling efficiency and restricts the extension distance achievable. Inspired by the structure and movement principle of an earthworm, we propose an earthworm-like load transfer method for the drillstring to address this issue. Specifically, the proposed method involves the installation of a pulse generator and multiple vibration subs within the same drillstring, decomposes the drillstring into multiple sections and modulates it to creep like an earthworm, thus facilitating load transfer. Experimental studies and numerical simulations were conducted in this paper to explore the fundamental mechanisms of earthworm-like crawling, aiming to enhance the efficiency of load transfer within the drillstring. The experimental results suggest that adopting earthworm-like excitation can increase the load transfer efficiency of the drillstring by 36–52% compared to conventional drilling methods. However, if the drillstring experiences helical buckling, there is a significant decrease in the efficiency of load transfer. Meanwhile, a dynamic model of the drillstring, considering the 3D wellbore trajectory, multipoint excitation, Stribeck friction, and penetration rate, has been developed. The simulated results from the proposed model align well with the experimental results obtained before the drillstring buckling, with an error of less than 5%. The simulation results for a 1000-m drillstring indicate that the earthworm-like excitation significantly enhances the efficiency of load transfer compared to conventional drilling methods. This improvement is attributed to the increase in the proportion of reverse-motion drillstring segments by 35.8–40.25%, which will greatly reduce the instantaneous total vector frictional force of the entire drillstring.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140778963","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"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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