C. Nguyen, G. Loi, N. N. Zulkifli, M. I. Mahamad Amir, A. A. Abdul Manap, S. R. Mohd Shafian, A. Badalyan, P. Bedrikovetsky, A. Zeinijahromi
One of the key risks for a Carbon Capture Storage (CCS) project is injectivity decline. Evaporation of the connate brine in near-wellbore region during Carbon dioxide (CO2) injection may result in migration of clay particles leading to decline rock permeability and consequent loss of well injectivity. This paper presents results of three coreflooding experiments aiming investigation of the effect of rock dry-out during CO2 injection. Three sandstone core plugs with various permeabilities have been used. Pressure drops across the cores, brine saturation and produced clay fines concentration versus Pore Volume Injected (PVI) have been measured. The results show that higher core permeability is associated with a shorter core drying process. Core drying time has a magnitude of 105 PVI. A fast detachment of clay particles has been observed during brine displacement by gaseous CO2 which is explained by dominant detaching capillary force. Further brine evaporation yields additional particle detachment due to disappearance of brine pendular rings holding clay particles on the rock surface. A 1.6 to 4.75-fold of gas permeability reduction has been observed during evaporation of connate brine. Damaged permeability for gas can be explained by both salt precipitation and clay fines migration, while damaged permeability for brine is due to clay fines migration and consequent pore blockage.
{"title":"Fines Migration Associated with Rock Dry-Out During CO2 Injection","authors":"C. Nguyen, G. Loi, N. N. Zulkifli, M. I. Mahamad Amir, A. A. Abdul Manap, S. R. Mohd Shafian, A. Badalyan, P. Bedrikovetsky, A. Zeinijahromi","doi":"10.2118/217852-ms","DOIUrl":"https://doi.org/10.2118/217852-ms","url":null,"abstract":"\u0000 One of the key risks for a Carbon Capture Storage (CCS) project is injectivity decline. Evaporation of the connate brine in near-wellbore region during Carbon dioxide (CO2) injection may result in migration of clay particles leading to decline rock permeability and consequent loss of well injectivity. This paper presents results of three coreflooding experiments aiming investigation of the effect of rock dry-out during CO2 injection. Three sandstone core plugs with various permeabilities have been used. Pressure drops across the cores, brine saturation and produced clay fines concentration versus Pore Volume Injected (PVI) have been measured. The results show that higher core permeability is associated with a shorter core drying process. Core drying time has a magnitude of 105 PVI. A fast detachment of clay particles has been observed during brine displacement by gaseous CO2 which is explained by dominant detaching capillary force. Further brine evaporation yields additional particle detachment due to disappearance of brine pendular rings holding clay particles on the rock surface. A 1.6 to 4.75-fold of gas permeability reduction has been observed during evaporation of connate brine. Damaged permeability for gas can be explained by both salt precipitation and clay fines migration, while damaged permeability for brine is due to clay fines migration and consequent pore blockage.","PeriodicalId":518997,"journal":{"name":"Day 1 Wed, February 21, 2024","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527705","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
B. AlShammari, Mohamed Hedi Slama, K. Badrawy, R. Sunagatov, S. Fajardo, Mohannad Adel Sebaih, N. Rane, M. Al-Adwani, L. AlOtaibi, M. Al-Mousharji, H. Al-Mehanna
Carbonate stimulations typically require formation-dissolving chemicals to eliminate near-wellbore damage by dissolving rock matrix or generating conductive channels such as wormholes to improve connectivity between the wellbore and the reservoir. Hydrochloric acid (HCl) has been a common choice for this purpose. However, commercially available emulsified acids, which contain acid droplets within a hydrocarbon phase, are preferred for acidifying carbonate at high temperatures. Nevertheless, these emulsified acids are usually highly viscous, leading to high friction pressure that cannot be mitigated by conventional friction reducers. In contrast, a more efficient single-phase retarded inorganic acid system (SPRIAS) was introduced to overcome these limitations. This paper presents a successful case study of SPRIAS's application in the oil and gas industry, particularly in high-temperature carbonate reservoirs. Advanced simulation software was used to model longer, intricate wormholes in high-temperature carbonate reservoirs. Selecting appropriate fluid solutions was crucial to optimize the stimulation treatment results. After laboratory testing, SPRIAS fluid was proposed to enhance the fluid selection. This addition to the selected treatment fluids improved the dissolution profile in the producing zone while reducing the reaction in the formation face. The successful application of SPRIAS resulted in a significant improvement in production rates and a longer productive life for the reservoir. This study demonstrates the effectiveness of SPRIAS in optimizing stimulation treatments for high-temperature carbonate reservoirs. This study examines two underperforming oil wells, X and Y, in South-East Kuwait, completed with 3.5-in tubing and 5.5-in liner, intersecting Middle Marrat, a tight carbonate formation with an average pressure of 9,500 psi and a bottomhole temperature of 240 DegF. The wells have a total depth of 12,700 ft and 13,400 ft, respectively, and production tubing set at 11,300 ft and 11,900 ft. SPRIAS system and viscoelastic diversion system were used to enhance the stimulation treatment results in high-temperature carbonate reservoirs. The execution began with drifting the well to target depth with a 1.75-in coiled tubing (CT), followed by injecting an aromatic solvent mixture across the liner to dissolve organic deposits. A stimulation treatment was performed, including a pre-flush, spearhead acid, and stages of SPRIAS paired with diversion. The post-stimulation production results for both wells showed a 4-to-5-fold increase in oil production. The selected fluids exhibited better solubility and controlled reaction rates, which optimized the treatment volume and increased the profitability of the stimulation treatments. This paper presents a novel approach to reviving a well's production while maintaining optimal economic values for high-pressure carbonate formations. The success of the proposed stimulation approach delivered breakt
{"title":"Achieving Resurgence in Underperforming Wells: The Winning Combination of Coiled Tubing Intervention paired with Single Phase Retarded Inorganic Acid System – A Story of Success from South-East Kuwait","authors":"B. AlShammari, Mohamed Hedi Slama, K. Badrawy, R. Sunagatov, S. Fajardo, Mohannad Adel Sebaih, N. Rane, M. Al-Adwani, L. AlOtaibi, M. Al-Mousharji, H. Al-Mehanna","doi":"10.2118/217844-ms","DOIUrl":"https://doi.org/10.2118/217844-ms","url":null,"abstract":"\u0000 Carbonate stimulations typically require formation-dissolving chemicals to eliminate near-wellbore damage by dissolving rock matrix or generating conductive channels such as wormholes to improve connectivity between the wellbore and the reservoir. Hydrochloric acid (HCl) has been a common choice for this purpose. However, commercially available emulsified acids, which contain acid droplets within a hydrocarbon phase, are preferred for acidifying carbonate at high temperatures. Nevertheless, these emulsified acids are usually highly viscous, leading to high friction pressure that cannot be mitigated by conventional friction reducers. In contrast, a more efficient single-phase retarded inorganic acid system (SPRIAS) was introduced to overcome these limitations. This paper presents a successful case study of SPRIAS's application in the oil and gas industry, particularly in high-temperature carbonate reservoirs.\u0000 Advanced simulation software was used to model longer, intricate wormholes in high-temperature carbonate reservoirs. Selecting appropriate fluid solutions was crucial to optimize the stimulation treatment results. After laboratory testing, SPRIAS fluid was proposed to enhance the fluid selection. This addition to the selected treatment fluids improved the dissolution profile in the producing zone while reducing the reaction in the formation face. The successful application of SPRIAS resulted in a significant improvement in production rates and a longer productive life for the reservoir. This study demonstrates the effectiveness of SPRIAS in optimizing stimulation treatments for high-temperature carbonate reservoirs.\u0000 This study examines two underperforming oil wells, X and Y, in South-East Kuwait, completed with 3.5-in tubing and 5.5-in liner, intersecting Middle Marrat, a tight carbonate formation with an average pressure of 9,500 psi and a bottomhole temperature of 240 DegF. The wells have a total depth of 12,700 ft and 13,400 ft, respectively, and production tubing set at 11,300 ft and 11,900 ft. SPRIAS system and viscoelastic diversion system were used to enhance the stimulation treatment results in high-temperature carbonate reservoirs. The execution began with drifting the well to target depth with a 1.75-in coiled tubing (CT), followed by injecting an aromatic solvent mixture across the liner to dissolve organic deposits. A stimulation treatment was performed, including a pre-flush, spearhead acid, and stages of SPRIAS paired with diversion. The post-stimulation production results for both wells showed a 4-to-5-fold increase in oil production. The selected fluids exhibited better solubility and controlled reaction rates, which optimized the treatment volume and increased the profitability of the stimulation treatments.\u0000 This paper presents a novel approach to reviving a well's production while maintaining optimal economic values for high-pressure carbonate formations. The success of the proposed stimulation approach delivered breakt","PeriodicalId":518997,"journal":{"name":"Day 1 Wed, February 21, 2024","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527580","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Zillur Rahim, Mark Watson, Stuart Wilson, Pablo Barbero
To attain higher hydrocarbon production and maintain oil and gas rates at optimal values for a determined time require prudent drilling, and subsequently completing and fracturing the well. are some of the essential criteria for positive cash flow. Oil and gas production is essential to meet world energy demand. The objective of any hydrocarbon field development is to attain higher sustained production rates. The need for the use of best practices in drilling, completion, fracturing, and production management during the duration of a well becomes essential. Drilling of long horizontal laterals through the reservoir section has been a game-changing alternate to vertical wells. Production is substantially increased with horizontal wells; long-term sustainability is achieved and development cost is considerably reduced. This paper highlights state of the art completions and fracturing technology used in moderate to tight oil and gas reservoirs for enhanced and sustained productivity. After proper assessment of the field using data from geoscience, delineation wells, and logs, an optimal horizontal drilling design is put together. Wells drilled in the field can be completed in multiple ways depending on the reservoir properties, well trajectory, and production objectives. The best completions are those that are customized for the reservoir parameters and well trajectory and will provide optimal inflow of reservoir fluids to the well. The best fracturing technique is to place a high conductivity path between the well and reservoir without causing damage to either the reservoir or completions. Depending on the reservoir, acid or proppants are selected such that fracture conductivity is maintained through most of well life. Many examples are provided in this paper.
{"title":"Improved Completions and Fracturing Technology Enhances Efficiency and Sustained Oil and Gas Production","authors":"Zillur Rahim, Mark Watson, Stuart Wilson, Pablo Barbero","doi":"10.2118/217901-ms","DOIUrl":"https://doi.org/10.2118/217901-ms","url":null,"abstract":"\u0000 To attain higher hydrocarbon production and maintain oil and gas rates at optimal values for a determined time require prudent drilling, and subsequently completing and fracturing the well. are some of the essential criteria for positive cash flow.\u0000 Oil and gas production is essential to meet world energy demand. The objective of any hydrocarbon field development is to attain higher sustained production rates. The need for the use of best practices in drilling, completion, fracturing, and production management during the duration of a well becomes essential. Drilling of long horizontal laterals through the reservoir section has been a game-changing alternate to vertical wells. Production is substantially increased with horizontal wells; long-term sustainability is achieved and development cost is considerably reduced.\u0000 This paper highlights state of the art completions and fracturing technology used in moderate to tight oil and gas reservoirs for enhanced and sustained productivity. After proper assessment of the field using data from geoscience, delineation wells, and logs, an optimal horizontal drilling design is put together. Wells drilled in the field can be completed in multiple ways depending on the reservoir properties, well trajectory, and production objectives. The best completions are those that are customized for the reservoir parameters and well trajectory and will provide optimal inflow of reservoir fluids to the well. The best fracturing technique is to place a high conductivity path between the well and reservoir without causing damage to either the reservoir or completions. Depending on the reservoir, acid or proppants are selected such that fracture conductivity is maintained through most of well life. Many examples are provided in this paper.","PeriodicalId":518997,"journal":{"name":"Day 1 Wed, February 21, 2024","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527727","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. K. Meybodi, K. Sorbie, O. Vazquez, K. Jarrahian, E. J. Mackay
Scale inhibitor squeeze treatments are one of the most common ways to prevent scale deposition. The mineral scale will be inhibited if the concentration of the scale inhibitor (SI) in the produced water is above a certain threshold, known as the Minimum Inhibitor Concentration (MIC), which is controlled by scale inhibitor retention. Therefore, accurate modelling of the SI retention through adsorption (Γ) and precipitation (Π) is critical to the successful design and implementation of squeeze treatments. In this study, an equilibrium model has been developed to simulate the coupled adsorption-precipitation (Γ/Π) of phosphonate scale inhibitors in reactive formations, such as carbonates, in the presence of calcium and magnesium cations. In this approach, the scale inhibitor (SI) was considered as a poly weak acid that may be protonated (HnA), resulting in the complexation with Ca/Mg ions, leading to the precipitation of SI_Ca/Mg complexes. All these reactions occur in an integrated system where carbonate system reactions and adsorption of the soluble species are occurring in parallel. In the adsorption process, all the SI derivatives remaining in the solution, including free and complex species, are considered to participate in the adsorption process, described by an an adsorption isotherm model (e.g., Freundlich). For the precipitation part, the model considers the following reactions: (i) the carbonate system, (ii) SI speciation, considered as weak polyacid, HnA, (iii) the SI-metal (Ca and Mg) binding complexes, and (iv) subsequent precipitation of the SI-Ca/Mg complex. The system charge balance and the mass balances for calcium, magnesium, carbon, and SI are considered, to numerically equilibrate the system (excluding the adsorbed species), by solving a determined set of non-linear equations numerically. Following the algebraic reduction of the equations, the system is reduced to three non-linear equations that may be solved by the Newton-Raphson method. The precipitation of the SI-Ca/Mg is modelled in the equilibrium model based on the solubility of SI in the solution, determined from the lab experiments. The reliability of the proposed model was established by comparison with experimental results from a previous study (Kalantari Meybodi et al., 2023) on the interactions of DETPMP in a Calcite/brine (containing free Ca/Mg) system, where the final concentration of SI, Ca2+, Mg2+, CO2 and pH were compared. The modelling showed good general agreement with the experimental results, and a further sensitivity analysis was performed to examine the behaviour of some uncertain parameters, such as the stability constant of complexes.
阻垢剂挤压处理是防止水垢沉积的最常见方法之一。如果产水中的阻垢剂（SI）浓度高于某个阈值，即最小阻垢剂浓度（MIC），矿物垢就会被抑制。因此，通过吸附（Γ）和沉淀（Π）对 SI 的滞留进行精确建模对于成功设计和实施挤压处理至关重要。本研究建立了一个平衡模型，用于模拟膦酸盐阻垢剂在钙镁阳离子存在下，在碳酸盐等活性地层中的吸附-沉淀（Γ/Π）耦合过程。在这种方法中，阻垢剂 (SI) 被视为一种多弱酸，可能会被质子化 (HnA)，从而与钙/镁离子发生络合反应，导致 SI_Ca/Mg 复合物沉淀。所有这些反应都发生在一个综合系统中，碳酸盐系统反应和可溶性物质的吸附同时进行。在吸附过程中，所有残留在溶液中的 SI 衍生物，包括游离和复合物种，都被认为参与了吸附过程，吸附等温线模型（如 Freundlich）对此进行了描述。对于沉淀部分，该模型考虑了以下反应：(i) 碳酸盐系统，(ii) SI（被认为是弱多酸的 HnA）标本，(iii) SI-金属（钙和镁）结合复合物，以及 (iv) SI-Ca/Mg 复合物的后续沉淀。考虑到系统电荷平衡以及钙、镁、碳和 SI 的质量平衡，通过数值求解一组确定的非线性方程，对系统（不包括吸附物种）进行数值平衡。在对方程进行代数还原后，系统简化为三个非线性方程，可以用牛顿-拉斐森方法求解。根据实验室实验确定的 SI 在溶液中的溶解度，在平衡模型中模拟了 SI-Ca/Mg 的沉淀。通过与之前一项研究（Kalantari Meybodi 等人，2023 年）中关于 DETPMP 在方解石/盐水（含游离 Ca/Mg）体系中的相互作用的实验结果进行比较，确定了所提模型的可靠性，其中对 SI、Ca2+、Mg2+、CO2 和 pH 的最终浓度进行了比较。建模结果显示与实验结果基本吻合，并进行了进一步的敏感性分析，以研究一些不确定参数的行为，如络合物的稳定常数。
{"title":"Coupled Adsorption/Precipitation Modelling of Phosphonate Scale Inhibitors in a Batch Reactive System","authors":"M. K. Meybodi, K. Sorbie, O. Vazquez, K. Jarrahian, E. J. Mackay","doi":"10.2118/217904-ms","DOIUrl":"https://doi.org/10.2118/217904-ms","url":null,"abstract":"\u0000 Scale inhibitor squeeze treatments are one of the most common ways to prevent scale deposition. The mineral scale will be inhibited if the concentration of the scale inhibitor (SI) in the produced water is above a certain threshold, known as the Minimum Inhibitor Concentration (MIC), which is controlled by scale inhibitor retention. Therefore, accurate modelling of the SI retention through adsorption (Γ) and precipitation (Π) is critical to the successful design and implementation of squeeze treatments.\u0000 In this study, an equilibrium model has been developed to simulate the coupled adsorption-precipitation (Γ/Π) of phosphonate scale inhibitors in reactive formations, such as carbonates, in the presence of calcium and magnesium cations. In this approach, the scale inhibitor (SI) was considered as a poly weak acid that may be protonated (HnA), resulting in the complexation with Ca/Mg ions, leading to the precipitation of SI_Ca/Mg complexes. All these reactions occur in an integrated system where carbonate system reactions and adsorption of the soluble species are occurring in parallel.\u0000 In the adsorption process, all the SI derivatives remaining in the solution, including free and complex species, are considered to participate in the adsorption process, described by an an adsorption isotherm model (e.g., Freundlich). For the precipitation part, the model considers the following reactions: (i) the carbonate system, (ii) SI speciation, considered as weak polyacid, HnA, (iii) the SI-metal (Ca and Mg) binding complexes, and (iv) subsequent precipitation of the SI-Ca/Mg complex. The system charge balance and the mass balances for calcium, magnesium, carbon, and SI are considered, to numerically equilibrate the system (excluding the adsorbed species), by solving a determined set of non-linear equations numerically. Following the algebraic reduction of the equations, the system is reduced to three non-linear equations that may be solved by the Newton-Raphson method. The precipitation of the SI-Ca/Mg is modelled in the equilibrium model based on the solubility of SI in the solution, determined from the lab experiments.\u0000 The reliability of the proposed model was established by comparison with experimental results from a previous study (Kalantari Meybodi et al., 2023) on the interactions of DETPMP in a Calcite/brine (containing free Ca/Mg) system, where the final concentration of SI, Ca2+, Mg2+, CO2 and pH were compared. The modelling showed good general agreement with the experimental results, and a further sensitivity analysis was performed to examine the behaviour of some uncertain parameters, such as the stability constant of complexes.","PeriodicalId":518997,"journal":{"name":"Day 1 Wed, February 21, 2024","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527724","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In many respects formation damage challenges in CO2 storage wells are similar to those in conventional oil and gas production wells and water and gas injection wells. But there are some differences from "conventional" well formation damage challenges. This paper outlines some issues specific to CO2 injection wells and proposes changes in focus prior to and during drilling and completion of these wells. CCS (Carbon Capture and Storage) store can generally be split in to two categories – saline aquifers and depleted hydrocarbon reservoirs. Wells drilled and/or completed in these stores share some well injectivity challenges with conventional wells but also have some challenges specific to the store properties. In conventional injection wells it is generally accepted that well clean-up or back production prior to injection is beneficial as formation damage necessarily induced during well drilling and clean-up may be partially or fully removed. For saline aquifers and depleted hydrocarbon stores, well clean-up is normally not possible or practical. Direct injection after well completion is often required. A new workflow capturing the key steps required to assure optimum well injectivity over the well life cycle has been developed and will be outlined in the paper. This includes but is not limited to: detailed analysis of CO2 phase behaviour in and beyond the lower completion; lower completion selection criteria specific to CO2 stores; laboratory testing and modelling focussed on CO2 store formation damage challenges; direct injection challenges and successful mitigations; ice scale and hydrate challenges in CO2 storage wells. With increasing focus on CO2 storage globally, the workflow outlined presents an integrated approach to formation damage challenges. It demonstrates that although many of the challenges are similar to those in conventional wells, there are also some that are different and unique – the same, but different!
在许多方面，二氧化碳封存井所面临的地层破坏挑战与常规油气生产井和注水注气井类似。但与 "常规 "井的地层损害挑战也有一些不同之处。本文概述了 CO2 注水井特有的一些问题，并提出了在钻井和完井前以及钻井和完井过程中应重点关注的变化。CCS（碳捕集与封存）存储一般可分为两类--含盐含水层和枯竭碳氢化合物储层。在这些储层中钻探和/或完工的油井与常规油井一样，都会面临一些油井注入方面的挑战，但也会面临一些储层特性所特有的挑战。在常规注水井中，人们普遍认为在注水前进行油井清理或回采是有益的，因为在钻井和清理过程中必然引起的地层损害可能会部分或全部消除。对于含盐含水层和枯竭碳氢化合物储藏，通常不可能或不可能进行油井清理。通常需要在完井后直接注入。我们开发了一种新的工作流程，其中包含了在油井生命周期内确保最佳油井注入率所需的关键步骤，本文将对此进行概述。这包括但不限于：对下部完井内和完井后的二氧化碳相行为进行详细分析；针对二氧化碳封存的下部完井选择标准；针对二氧化碳封存地层破坏挑战的实验室测试和建模；直接注入挑战和成功的缓解措施；二氧化碳封存井中的冰垢和水合物挑战。随着全球对二氧化碳封存的关注日益增加，所概述的工作流程提出了应对地层损害挑战的综合方法。它表明，虽然许多挑战与常规井中的挑战相似，但也有一些不同和独特的挑战--相同但不同！
{"title":"Formation Damage in CO2 Storage Wells – The Same, But Different","authors":"M. Byrne, R. Gilbert, R. Anderson","doi":"10.2118/217859-ms","DOIUrl":"https://doi.org/10.2118/217859-ms","url":null,"abstract":"\u0000 In many respects formation damage challenges in CO2 storage wells are similar to those in conventional oil and gas production wells and water and gas injection wells. But there are some differences from \"conventional\" well formation damage challenges. This paper outlines some issues specific to CO2 injection wells and proposes changes in focus prior to and during drilling and completion of these wells.\u0000 CCS (Carbon Capture and Storage) store can generally be split in to two categories – saline aquifers and depleted hydrocarbon reservoirs. Wells drilled and/or completed in these stores share some well injectivity challenges with conventional wells but also have some challenges specific to the store properties. In conventional injection wells it is generally accepted that well clean-up or back production prior to injection is beneficial as formation damage necessarily induced during well drilling and clean-up may be partially or fully removed. For saline aquifers and depleted hydrocarbon stores, well clean-up is normally not possible or practical. Direct injection after well completion is often required.\u0000 A new workflow capturing the key steps required to assure optimum well injectivity over the well life cycle has been developed and will be outlined in the paper. This includes but is not limited to: detailed analysis of CO2 phase behaviour in and beyond the lower completion; lower completion selection criteria specific to CO2 stores; laboratory testing and modelling focussed on CO2 store formation damage challenges; direct injection challenges and successful mitigations; ice scale and hydrate challenges in CO2 storage wells.\u0000 With increasing focus on CO2 storage globally, the workflow outlined presents an integrated approach to formation damage challenges. It demonstrates that although many of the challenges are similar to those in conventional wells, there are also some that are different and unique – the same, but different!","PeriodicalId":518997,"journal":{"name":"Day 1 Wed, February 21, 2024","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527568","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Dispersion, which poses a significant challenge to wellbore stability during shale drilling, is influenced by various factors such as shale petrological and mechanical properties, as well as shale-fluid interactions. The effectiveness of shale inhibitors in alleviating these interactions has traditionally been evaluated using the standardized conventional dispersion test. In this test, measured quantities of sized shale particles are exposed to formulated fluids in a roller-oven cell for a specified duration. Subsequently, the shale particles are washed, dried, and the recovery percentage is determined, with higher rates indicating improved inhibitor performance. While the conventional dispersion test is widely used due to its simplicity, the test provides limited, and at times, misleading information. This paper presents an enhanced dispersion test method and analysis by incorporating particle size analysis and inductively coupled plasma optical emission spectroscopy (ICP-OES) tests before and after the conventional dispersion test. Three standard shales exhibiting diverse reactive and dispersive characteristics are selected along with three fluids containing different chemicals and inhibitors for conducting these advanced dispersion tests and analyses. The study highlights the capabilities of the new method for obtaining comprehensive data, not only the recovery rate at a specific particle size but also the particle size distribution curves before and after the dispersion tests. Analyses of particle size distribution provide valuable insights into the particle size shift after shales interact with different fluids. This detailed understanding of the dispersion properties contributes to a more effective design and optimization of shale inhibitors and enhances borehole cleaning processes. Additionally, the application of ICP-OES analysis enables the identification of cation exchanges between the drilling fluids and shales and the exploration of the relationship between cation exchange and dispersion. A higher release of Ca2+ indicates potentially stronger dispersion.
{"title":"Enhancing Dispersion Test Analysis for Shale Drilling: Particle Size Distribution and Cation Exchange Insights","authors":"Bitao Lai, Jihong Wang, Wenwu He, Zhipeng Wan","doi":"10.2118/217889-ms","DOIUrl":"https://doi.org/10.2118/217889-ms","url":null,"abstract":"\u0000 Dispersion, which poses a significant challenge to wellbore stability during shale drilling, is influenced by various factors such as shale petrological and mechanical properties, as well as shale-fluid interactions. The effectiveness of shale inhibitors in alleviating these interactions has traditionally been evaluated using the standardized conventional dispersion test. In this test, measured quantities of sized shale particles are exposed to formulated fluids in a roller-oven cell for a specified duration. Subsequently, the shale particles are washed, dried, and the recovery percentage is determined, with higher rates indicating improved inhibitor performance. While the conventional dispersion test is widely used due to its simplicity, the test provides limited, and at times, misleading information.\u0000 This paper presents an enhanced dispersion test method and analysis by incorporating particle size analysis and inductively coupled plasma optical emission spectroscopy (ICP-OES) tests before and after the conventional dispersion test. Three standard shales exhibiting diverse reactive and dispersive characteristics are selected along with three fluids containing different chemicals and inhibitors for conducting these advanced dispersion tests and analyses.\u0000 The study highlights the capabilities of the new method for obtaining comprehensive data, not only the recovery rate at a specific particle size but also the particle size distribution curves before and after the dispersion tests. Analyses of particle size distribution provide valuable insights into the particle size shift after shales interact with different fluids. This detailed understanding of the dispersion properties contributes to a more effective design and optimization of shale inhibitors and enhances borehole cleaning processes. Additionally, the application of ICP-OES analysis enables the identification of cation exchanges between the drilling fluids and shales and the exploration of the relationship between cation exchange and dispersion. A higher release of Ca2+ indicates potentially stronger dispersion.","PeriodicalId":518997,"journal":{"name":"Day 1 Wed, February 21, 2024","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527702","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
K. Katterbauer, A. Qasim, Abdallah Al Shehri, Ali Yousef
A particularly corrosive and poisonous by-product of a range of feedstocks, including fossil resources like coal and natural gas as well as renewable resources, is hydrogen sulfide (H2S). H2S is also a possible source of hydrogen gas, a significant green energy carrier. Our business would greatly benefit from the recovery of H2 from chemical compounds that have been classified as pollutants, such as H2S. Due to the large volumes of H2S that are readily accessible across the world and the expanding significance of hydrogen and its by-products in the global energy landscape, attempts have been undertaken in recent years to separate H2 and Sulphur from H2S using various methods. In addition to deep gas reservoirs, hydrogen sulfide may be found in a wide range of other reservoir types. Due to their low use, these gas reserves often have little economic viability. Thanks to novel strategies for converting hydrogen sulfide into hydrogen and its remaining components, it has become possible to efficiently recover hydrocarbons and its hydrogen sulfide components. This paper introduces a unique deep learning (DL) architecture for improving field recovery over time based on thermal-enhanced recovery. We investigated performance of the framework on the Maari Field in New Zealand. The ultimate goal is to optimize recovery and, within the limits of processing, reach a specific volume of H2S. The optimization results indicate the ability to increase oil and natural gas recovery while constraining H2S levels within the reservoir and converting the associated H2S into hydrogen. The deep learning architecture that has been built provides a technique for developing field strategies to improve sustainability for thermal-enhanced recovery strategies. The framework is flexible enough to incorporate additional reservoir and production parameters.
{"title":"A Deep Learning Framework for Thermal Enhanced Oil Recovery Optimization of Hydrogen from H2S – A Maari Reservoir Study","authors":"K. Katterbauer, A. Qasim, Abdallah Al Shehri, Ali Yousef","doi":"10.2118/217886-ms","DOIUrl":"https://doi.org/10.2118/217886-ms","url":null,"abstract":"\u0000 A particularly corrosive and poisonous by-product of a range of feedstocks, including fossil resources like coal and natural gas as well as renewable resources, is hydrogen sulfide (H2S). H2S is also a possible source of hydrogen gas, a significant green energy carrier. Our business would greatly benefit from the recovery of H2 from chemical compounds that have been classified as pollutants, such as H2S. Due to the large volumes of H2S that are readily accessible across the world and the expanding significance of hydrogen and its by-products in the global energy landscape, attempts have been undertaken in recent years to separate H2 and Sulphur from H2S using various methods. In addition to deep gas reservoirs, hydrogen sulfide may be found in a wide range of other reservoir types. Due to their low use, these gas reserves often have little economic viability. Thanks to novel strategies for converting hydrogen sulfide into hydrogen and its remaining components, it has become possible to efficiently recover hydrocarbons and its hydrogen sulfide components.\u0000 This paper introduces a unique deep learning (DL) architecture for improving field recovery over time based on thermal-enhanced recovery. We investigated performance of the framework on the Maari Field in New Zealand. The ultimate goal is to optimize recovery and, within the limits of processing, reach a specific volume of H2S. The optimization results indicate the ability to increase oil and natural gas recovery while constraining H2S levels within the reservoir and converting the associated H2S into hydrogen. The deep learning architecture that has been built provides a technique for developing field strategies to improve sustainability for thermal-enhanced recovery strategies. The framework is flexible enough to incorporate additional reservoir and production parameters.","PeriodicalId":518997,"journal":{"name":"Day 1 Wed, February 21, 2024","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527712","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In this paper, we examine wellbore integrity during carbon dioxide (CO2) injection in deep saline aquifers, by modeling stress-distribution evolutions within the casing-cement sheath-rock formation (C/CS/RF) system. For our analysis, a mechanistic model is used, which considers a total of eleven ("10 + 1") modes of mechanical degradation assessing each of the three layers of the C/CS/RF system discretely. The integrity of the wellbore is assessed by modeling the casing layer as a thick-walled cylinder and the adjacent-RF layer as a poroelastic solid, accounting for fluid infiltration into and out of the pores in close proximity to the CS layer. The magnitude of the normal-effective stresses at the C/CS and CS/RF interfaces provide calibration parameters for the stress distributions within the intermediate-CS layer, honoring linear elasticity. This novel method is used to determine the initial state of stress within the C/CS/RF system with balanced conditions inside the wellbore, following cement setting. Using input data from the literature, the integrity of the C/CS/RF system is assessed over a 30-year period of bulk-CO2 injection in a closed (bounded) system and an open (unbounded) system subsurface aquifer. In closed-aquifer configurations, disking failures along with radial and shear cracking tendencies are indicated within the CS layer, providing potential pathways for CO2 leakages back into the atmosphere. In open-aquifer configurations, the three aforementioned tendencies for mechanical degradation remain, albeit at a smaller degree. The generated stress distributions demonstrate no indication of inner debonding along the C/CS interface, while the outer-debonding limit is approached on the CS/RF interface, but never exceeded. Moreover, no tensile failures (via longitudinal or transverse-fracture initiation) is expected along the CS/RF interface, nor casing failures (related to compressive/tensile loads, collapse and burst stress loads). Finally, none of the scenarios considered are expected to generate seismic activity along preexisting faults (PEFs) near the injection well.
{"title":"Mechanistic Modeling of Wellbore Integrity During CO2 Injection in Deep Saline Aquifers","authors":"Jawad Ali Khan, Andreas Michael","doi":"10.2118/217873-ms","DOIUrl":"https://doi.org/10.2118/217873-ms","url":null,"abstract":"\u0000 In this paper, we examine wellbore integrity during carbon dioxide (CO2) injection in deep saline aquifers, by modeling stress-distribution evolutions within the casing-cement sheath-rock formation (C/CS/RF) system. For our analysis, a mechanistic model is used, which considers a total of eleven (\"10 + 1\") modes of mechanical degradation assessing each of the three layers of the C/CS/RF system discretely.\u0000 The integrity of the wellbore is assessed by modeling the casing layer as a thick-walled cylinder and the adjacent-RF layer as a poroelastic solid, accounting for fluid infiltration into and out of the pores in close proximity to the CS layer. The magnitude of the normal-effective stresses at the C/CS and CS/RF interfaces provide calibration parameters for the stress distributions within the intermediate-CS layer, honoring linear elasticity. This novel method is used to determine the initial state of stress within the C/CS/RF system with balanced conditions inside the wellbore, following cement setting. Using input data from the literature, the integrity of the C/CS/RF system is assessed over a 30-year period of bulk-CO2 injection in a closed (bounded) system and an open (unbounded) system subsurface aquifer.\u0000 In closed-aquifer configurations, disking failures along with radial and shear cracking tendencies are indicated within the CS layer, providing potential pathways for CO2 leakages back into the atmosphere. In open-aquifer configurations, the three aforementioned tendencies for mechanical degradation remain, albeit at a smaller degree. The generated stress distributions demonstrate no indication of inner debonding along the C/CS interface, while the outer-debonding limit is approached on the CS/RF interface, but never exceeded. Moreover, no tensile failures (via longitudinal or transverse-fracture initiation) is expected along the CS/RF interface, nor casing failures (related to compressive/tensile loads, collapse and burst stress loads). Finally, none of the scenarios considered are expected to generate seismic activity along preexisting faults (PEFs) near the injection well.","PeriodicalId":518997,"journal":{"name":"Day 1 Wed, February 21, 2024","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527561","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Formation damage during CO2 injection into depleted gas or oil reservoirs, or in aquifers, is highly affected by connate water evaporation into injected gas. For example, precipitated salts accumulate into dried-up zone around the well. Dried rock liberates fine clay particles. The aim of the work is creation of an analytical model for connate water evaporation into injected CO2 during coreflood and injection in vertical well. The mathematical model considers non-equilibrium evaporation accounting for changing interfacial area. The interfacial area is derived separately from approximating the porous media as a sphere pack and from the averaging of individual water patches. The resulting model is solved analytically using the method of characteristics, permitting the calculation of the water saturation and vapour concentration profiles during the evaporation process. Finally, we match 5 laboratory tests, determine the typical form of evaporation interface, and upscale the results for injection well conditions. Tuning of laboratory data exhibits high agreement for 5 laboratory tests and allows for characterization of field-scale evaporation dynamics from laboratory testing. The total evaporation time is provided explicitly by the model, and a criterion is presented for determining whether evaporation occurs within finite time. This work provides key insights into the behaviour of CO2 injection wells and can contribute to producing explicit formulae to predict mobilisation of fine clays and precipitation of salts due to rock drying.
{"title":"An Analytical Model for Water Evaporation During CO2 Injection for Geological Storage","authors":"T. Russell, P. Bedrikovetsky","doi":"10.2118/217892-ms","DOIUrl":"https://doi.org/10.2118/217892-ms","url":null,"abstract":"\u0000 Formation damage during CO2 injection into depleted gas or oil reservoirs, or in aquifers, is highly affected by connate water evaporation into injected gas. For example, precipitated salts accumulate into dried-up zone around the well. Dried rock liberates fine clay particles. The aim of the work is creation of an analytical model for connate water evaporation into injected CO2 during coreflood and injection in vertical well.\u0000 The mathematical model considers non-equilibrium evaporation accounting for changing interfacial area. The interfacial area is derived separately from approximating the porous media as a sphere pack and from the averaging of individual water patches. The resulting model is solved analytically using the method of characteristics, permitting the calculation of the water saturation and vapour concentration profiles during the evaporation process. Finally, we match 5 laboratory tests, determine the typical form of evaporation interface, and upscale the results for injection well conditions.\u0000 Tuning of laboratory data exhibits high agreement for 5 laboratory tests and allows for characterization of field-scale evaporation dynamics from laboratory testing. The total evaporation time is provided explicitly by the model, and a criterion is presented for determining whether evaporation occurs within finite time. This work provides key insights into the behaviour of CO2 injection wells and can contribute to producing explicit formulae to predict mobilisation of fine clays and precipitation of salts due to rock drying.","PeriodicalId":518997,"journal":{"name":"Day 1 Wed, February 21, 2024","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527703","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The degradation of cement due to CO2 exposure affects its transport and mechanical properties, resulting in potential fluid leakage from wells used for CCUS. This study focused on investigating the mechanisms of cement degradation in CO2 injection wells. We employ a fully integrated 3-D reservoir simulator that incorporates fluid flow, geomechanics, and geochemistry, along with a new model designed to accurately replicate the changes in rock properties resulting from cement degradation. Chemical reactions, including dissolution and precipitation, between CO2-rich brine and cement minerals are modeled, allowing for changes in rock and cement properties. Porosity is recalculated considering volume changes due to chemical reactions, and permeability is reevaluated using the Kozeny-Carman equation. Based on the simulation results, the chemo-mechanical composite layer model reassesses mechanical properties, considering the mineral composition of cement. According to the simulation results, the chemical changes in cement exhibited three stages: 1) dissolution of primary minerals, 2) precipitation of carbonates, and 3) re-dissolution of carbonates. While reactions 1 and 2 played a major role, they led to a decrease in rock porosity and a degradation of mechanical properties. However, as the dissolution of primary minerals diminished and the transition from stage 2 to stage 3 began, the porosity increased, accompanied by an increase in mechanical stiffness. The predicted values of porosity were compared to experimental data obtained from prior studies, confirming their consistency for short-term CO2 exposure, which can be reproduced in experiments. These mechanisms of cement degradation and the alteration of mechanical properties that occur in CO2 injection wells agree well with experiments. Our numerical simulator that fully integrates flow, geochemistry, and geomechanics with a chemical reaction model can be used to model more complex cement geometries to evaluate the risks of CO2 escape along the wellbore annulus.
{"title":"Mechanisms of Degradation of Cement in CO2 Injection Wells: Maintaining the Integrity of CO2 Seals","authors":"Miki Mura, Mukul M. Sharma","doi":"10.2118/217872-ms","DOIUrl":"https://doi.org/10.2118/217872-ms","url":null,"abstract":"\u0000 The degradation of cement due to CO2 exposure affects its transport and mechanical properties, resulting in potential fluid leakage from wells used for CCUS. This study focused on investigating the mechanisms of cement degradation in CO2 injection wells. We employ a fully integrated 3-D reservoir simulator that incorporates fluid flow, geomechanics, and geochemistry, along with a new model designed to accurately replicate the changes in rock properties resulting from cement degradation. Chemical reactions, including dissolution and precipitation, between CO2-rich brine and cement minerals are modeled, allowing for changes in rock and cement properties. Porosity is recalculated considering volume changes due to chemical reactions, and permeability is reevaluated using the Kozeny-Carman equation. Based on the simulation results, the chemo-mechanical composite layer model reassesses mechanical properties, considering the mineral composition of cement. According to the simulation results, the chemical changes in cement exhibited three stages: 1) dissolution of primary minerals, 2) precipitation of carbonates, and 3) re-dissolution of carbonates. While reactions 1 and 2 played a major role, they led to a decrease in rock porosity and a degradation of mechanical properties. However, as the dissolution of primary minerals diminished and the transition from stage 2 to stage 3 began, the porosity increased, accompanied by an increase in mechanical stiffness. The predicted values of porosity were compared to experimental data obtained from prior studies, confirming their consistency for short-term CO2 exposure, which can be reproduced in experiments. These mechanisms of cement degradation and the alteration of mechanical properties that occur in CO2 injection wells agree well with experiments. Our numerical simulator that fully integrates flow, geochemistry, and geomechanics with a chemical reaction model can be used to model more complex cement geometries to evaluate the risks of CO2 escape along the wellbore annulus.","PeriodicalId":518997,"journal":{"name":"Day 1 Wed, February 21, 2024","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527562","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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