An Enhanced Geothermal System (EGS) uses flow through fractures in an effectively impermeable high-temperature rock formation to provide sustainable and affordable heat extraction that can be employed virtually anywhere with no need for a geothermal reservoir. The problem is that there is no commercial application of this technology. The three-well pattern introduced in this paper employs a multiple transverse fractured horizontal well (MTFHW) drilled and fractured in an effectively impermeable high-temperature formation. Two parallel horizontal wells drilled above and below or on opposing sides of the MTFHW have trajectories that intersect its created fractures. Fluid injected in the MTFHW flows through the fractures and horizontal wells, thus extracting heat from the surrounding high-temperature rock. This study aims to find the most cost-effective well and fracture spacing for this pattern to supply hot fluid to a 20-megawatt power plant. Analytical and numerical models compare heat transfer behavior for a single fracture unit in an MTFHW that is then replicated along with the horizontal well pattern(s). The Computer Modeling Group (CMG) STARS simulator is used to model the circulation of cold water injected into the center of a radial transverse hydraulic fracture and produced from two horizontal wells. Key factors to the design include formation temperature, the flow rate in fractures, the fractured radius, spacing, heat transfer, and pressure loss along the wells. The Aspen HYSYS software is used to model the geothermal power plant, and heat transfer and pressure loss in wells and fractures. The comparison between analytical and numerical models showed the simplified analytical model provides overly optimistic results and indicates the need for a numerical model. Sensitivity studies using the numerical model vary the key design factors and reveal how many fractures the plant requires. The economic performance of several scenarios was investigated to minimize well drilling and completion pattern costs. This study illustrates the viability of applying known and widely used well technologies in an enhanced geothermal system.
{"title":"Enhanced Geothermal System Model for Flow through a Stimulated Rock Volume","authors":"Leila Zeinali, C. Ehlig-Economides, M. Nikolaou","doi":"10.2118/205967-ms","DOIUrl":"https://doi.org/10.2118/205967-ms","url":null,"abstract":"\u0000 An Enhanced Geothermal System (EGS) uses flow through fractures in an effectively impermeable high-temperature rock formation to provide sustainable and affordable heat extraction that can be employed virtually anywhere with no need for a geothermal reservoir. The problem is that there is no commercial application of this technology. The three-well pattern introduced in this paper employs a multiple transverse fractured horizontal well (MTFHW) drilled and fractured in an effectively impermeable high-temperature formation. Two parallel horizontal wells drilled above and below or on opposing sides of the MTFHW have trajectories that intersect its created fractures. Fluid injected in the MTFHW flows through the fractures and horizontal wells, thus extracting heat from the surrounding high-temperature rock. This study aims to find the most cost-effective well and fracture spacing for this pattern to supply hot fluid to a 20-megawatt power plant.\u0000 Analytical and numerical models compare heat transfer behavior for a single fracture unit in an MTFHW that is then replicated along with the horizontal well pattern(s). The Computer Modeling Group (CMG) STARS simulator is used to model the circulation of cold water injected into the center of a radial transverse hydraulic fracture and produced from two horizontal wells. Key factors to the design include formation temperature, the flow rate in fractures, the fractured radius, spacing, heat transfer, and pressure loss along the wells. The Aspen HYSYS software is used to model the geothermal power plant, and heat transfer and pressure loss in wells and fractures.\u0000 The comparison between analytical and numerical models showed the simplified analytical model provides overly optimistic results and indicates the need for a numerical model. Sensitivity studies using the numerical model vary the key design factors and reveal how many fractures the plant requires. The economic performance of several scenarios was investigated to minimize well drilling and completion pattern costs.\u0000 This study illustrates the viability of applying known and widely used well technologies in an enhanced geothermal system.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78925201","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}
Matrix acidizing with fluoroboric acid (HBF4) has gained special attention as not only it provides deeper penetration of in – situ generated hydrofluoric acid, but also stabilizes formation fines by binding them to the pore surface. While numerous mathematical models exist in literature for design and evaluation of conventional mud acid treatments, fewer attempts have been made in developing a lab validated model that can do so for fluoroboric acid treatments. This paper presents a novel mathematical model that has been developed taking into account the chemical kinetics and equilibrium aspects of important reactions and fluid flow inside the reservoir rock. The solution to the governing equations has been obtained through tools of computational fluid dynamics (CFD). The model has been validated rigorously through use of state-of-the-art core flooding and ion chromatography setups. The resulting simulator can be used to design an optimum fluoroboric acid treatment by analysing the effects of all the important factors including reservoir temperature, formation mineralogy and job execution details like initial acid concentration, pumping rate, job volume and shut-in time post treatment. Simulation results with the developed model indicate that although penetration of fluoroboric acid is much larger compared to mud acid, its overall effect on skin factor is inferior for temperatures less than 90 °C. Stimulation in such wells should be preferred with mud acid which can be followed by fluoroboric acid for fines stabilization. For temperatures more than 120 °C, stimulation effects of fluoroboric acid become comparable to that of mud acid. Under these conditions, it can be used as an alternate fluid to mud acid to prevent issues of secondary and tertiary precipitation. It is found that major stimulation benefits with fluoroboric acid are realized during pumping and subsequent shutting of well, which is a common practice with fluoroboric acid, has relatively smaller effect on skin factor. Apart from design and evaluation of fluoroboric acid treatments, the simulator can also be used for analyzing mud acid and mud acid followed by fluoroboric acid treatments thus enabling the user to select and design the best suited treatment for a given well.
{"title":"Novel Simulator for Design and Analysis of Matrix Acidizing Jobs with Fluoroboric Acid in Sandstone Reservoirs","authors":"M. Qamruzzaman, Mandeep Khan, D. Roy, R. Raman","doi":"10.2118/205893-ms","DOIUrl":"https://doi.org/10.2118/205893-ms","url":null,"abstract":"\u0000 Matrix acidizing with fluoroboric acid (HBF4) has gained special attention as not only it provides deeper penetration of in – situ generated hydrofluoric acid, but also stabilizes formation fines by binding them to the pore surface. While numerous mathematical models exist in literature for design and evaluation of conventional mud acid treatments, fewer attempts have been made in developing a lab validated model that can do so for fluoroboric acid treatments.\u0000 This paper presents a novel mathematical model that has been developed taking into account the chemical kinetics and equilibrium aspects of important reactions and fluid flow inside the reservoir rock. The solution to the governing equations has been obtained through tools of computational fluid dynamics (CFD). The model has been validated rigorously through use of state-of-the-art core flooding and ion chromatography setups. The resulting simulator can be used to design an optimum fluoroboric acid treatment by analysing the effects of all the important factors including reservoir temperature, formation mineralogy and job execution details like initial acid concentration, pumping rate, job volume and shut-in time post treatment.\u0000 Simulation results with the developed model indicate that although penetration of fluoroboric acid is much larger compared to mud acid, its overall effect on skin factor is inferior for temperatures less than 90 °C. Stimulation in such wells should be preferred with mud acid which can be followed by fluoroboric acid for fines stabilization. For temperatures more than 120 °C, stimulation effects of fluoroboric acid become comparable to that of mud acid. Under these conditions, it can be used as an alternate fluid to mud acid to prevent issues of secondary and tertiary precipitation. It is found that major stimulation benefits with fluoroboric acid are realized during pumping and subsequent shutting of well, which is a common practice with fluoroboric acid, has relatively smaller effect on skin factor. Apart from design and evaluation of fluoroboric acid treatments, the simulator can also be used for analyzing mud acid and mud acid followed by fluoroboric acid treatments thus enabling the user to select and design the best suited treatment for a given well.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"90 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75718074","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}
Zeeshan Tariq, M. Aljawad, Mobeen Murtaza, M. Mahmoud, Dhafer Al-Shehri, A. Abdulraheem
Unconventional reservoirs are characterized by their extremely low permeabilities surrounded by huge in-situ stresses. Hydraulic fracturing is a most commonly used stimulation technique to produce from such reservoirs. Due to high in situ stresses, breakdown pressure of the rock can be too difficult to achieve despite of reaching maximum pumping capacity. In this study, a new model is proposed to predict the breakdown pressures of the rock. An extensive experimental study was carried out on different cylindrical specimens and the hydraulic fracturing stimulation was performed with different fracturing fluids. Stimulation was carried out to record the rock breakdown pressure. Different types of fracturing fluids such as slick water, linear gel, cross-linked gels, guar gum, and heavy oil were tested. The experiments were carried out on different types of rock samples such as shales, sandstone, and tight carbonates. An extensive rock mechanical study was conducted to measure the elastic and failure parameters of the rock samples tested. An artificial neural network was used to correlate the breakdown pressure of the rock as a function of fracturing fluids, experimental conditions, and rock properties. Fracturing fluid properties included injection rate and fluid viscosity. Rock properties included were tensile strength, unconfined compressive strength, Young's Modulus, Poisson's ratio, porosity, permeability, and bulk density. In the process of data training, we analyzed and optimized the parameters of the neural network, including activation function, number of hidden layers, number of neurons in each layer, training times, data set division, and obtained the optimal model suitable for prediction of breakdown pressure. With the optimal setting of the neural network, we were successfully able to predict the breakdown pressure of the unconventional formation with an accuracy of 95%. The proposed method can greatly reduce the prediction cost of rock breakdown pressure before the fracturing operation of new wells and provides an optional method for the evaluation of tight oil reservoirs.
{"title":"A Data-Driven Approach to Predict the Breakdown Pressure of the Tight and Unconventional Formation","authors":"Zeeshan Tariq, M. Aljawad, Mobeen Murtaza, M. Mahmoud, Dhafer Al-Shehri, A. Abdulraheem","doi":"10.2118/206136-ms","DOIUrl":"https://doi.org/10.2118/206136-ms","url":null,"abstract":"\u0000 Unconventional reservoirs are characterized by their extremely low permeabilities surrounded by huge in-situ stresses. Hydraulic fracturing is a most commonly used stimulation technique to produce from such reservoirs. Due to high in situ stresses, breakdown pressure of the rock can be too difficult to achieve despite of reaching maximum pumping capacity. In this study, a new model is proposed to predict the breakdown pressures of the rock. An extensive experimental study was carried out on different cylindrical specimens and the hydraulic fracturing stimulation was performed with different fracturing fluids. Stimulation was carried out to record the rock breakdown pressure. Different types of fracturing fluids such as slick water, linear gel, cross-linked gels, guar gum, and heavy oil were tested. The experiments were carried out on different types of rock samples such as shales, sandstone, and tight carbonates. An extensive rock mechanical study was conducted to measure the elastic and failure parameters of the rock samples tested. An artificial neural network was used to correlate the breakdown pressure of the rock as a function of fracturing fluids, experimental conditions, and rock properties. Fracturing fluid properties included injection rate and fluid viscosity. Rock properties included were tensile strength, unconfined compressive strength, Young's Modulus, Poisson's ratio, porosity, permeability, and bulk density. In the process of data training, we analyzed and optimized the parameters of the neural network, including activation function, number of hidden layers, number of neurons in each layer, training times, data set division, and obtained the optimal model suitable for prediction of breakdown pressure. With the optimal setting of the neural network, we were successfully able to predict the breakdown pressure of the unconventional formation with an accuracy of 95%. The proposed method can greatly reduce the prediction cost of rock breakdown pressure before the fracturing operation of new wells and provides an optional method for the evaluation of tight oil reservoirs.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88639604","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}
This paper will focus on a new system for separation of water in downhole horizontal wells. The advantages with the system are related to the fact that the water produced from the well is not lifted to the surface, but re-injected into suitable parts of the reservoir, either for pressure support or for diposal. The method of water separation and re-injection has been evaluated for oil producing fields. The paper presents details of the technical solutions and analysis done related to the financial analysis/payback. The mechanical design is basically a main pipe section of a few meters of length, with a special geometry utilizing gravity-based separation. A technical and economic analysis of a downhole processing plant (DPP) using a horizontally installed water/oil separator has been performed. The Improved Oil Recovery (IOR)part has been analysed with a relevant flow simulation tool. Based on the given reservoir depth/pressure, flow rate, viscosity/density and water cut, the simulations show that a significant improved production rate/income can be achieved by extracting the produced water downhole and performing re-injection into the producing reservoir to maintain reservoir pressure. In addition, the expected lifetime of the well is increased by several years. The conclusion is that the earlier the separator is installed, the greater the total well income. In addition, details regarding not only multi-lateral wells through level 5 junctions but also production string with separator and valve system has been evaluated and is concluded to be feasible for the well in question The removal of water downhole has several advantages, for example the removal of the water column up to the surface will reduce the reservoir back pressure and will improve recovery /production rates. In addition, not lifting the water will reduce energy consumption/CO2 footprint, and removal of water will reduce surface processing and possible re-injection and chemical treatment cost. In general, water separation downhole is advantageous, due to the higher pressure.
{"title":"Use of Downhole Oil-Water Separation System in Horizontal Wells","authors":"Ahmed Alshmakhy, A. Abdelkerim, N. Braaten","doi":"10.2118/205960-ms","DOIUrl":"https://doi.org/10.2118/205960-ms","url":null,"abstract":"\u0000 This paper will focus on a new system for separation of water in downhole horizontal wells. The advantages with the system are related to the fact that the water produced from the well is not lifted to the surface, but re-injected into suitable parts of the reservoir, either for pressure support or for diposal.\u0000 The method of water separation and re-injection has been evaluated for oil producing fields. The paper presents details of the technical solutions and analysis done related to the financial analysis/payback. The mechanical design is basically a main pipe section of a few meters of length, with a special geometry utilizing gravity-based separation.\u0000 A technical and economic analysis of a downhole processing plant (DPP) using a horizontally installed water/oil separator has been performed. The Improved Oil Recovery (IOR)part has been analysed with a relevant flow simulation tool. Based on the given reservoir depth/pressure, flow rate, viscosity/density and water cut, the simulations show that a significant improved production rate/income can be achieved by extracting the produced water downhole and performing re-injection into the producing reservoir to maintain reservoir pressure. In addition, the expected lifetime of the well is increased by several years. The conclusion is that the earlier the separator is installed, the greater the total well income. In addition, details regarding not only multi-lateral wells through level 5 junctions but also production string with separator and valve system has been evaluated and is concluded to be feasible for the well in question\u0000 The removal of water downhole has several advantages, for example the removal of the water column up to the surface will reduce the reservoir back pressure and will improve recovery /production rates. In addition, not lifting the water will reduce energy consumption/CO2 footprint, and removal of water will reduce surface processing and possible re-injection and chemical treatment cost. In general, water separation downhole is advantageous, due to the higher pressure.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"94 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80661583","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}
C. Teodoriu, O. Bello, R. Vasquez, Ryan M. Melander, Yosafat Esquitin
Well construction has relied on two main elements, casing and cement, to achieve the well goals while maintaining the highest possible well integrity. Can cementless well construction achieve similar goals? This paper is investigating the various well construction concepts proposed over the years and will analyze the cement's ability to withstand long term well loads. First, a review of various well construction concepts such as slimhole, conventional, pre-salt and horizontal wells. We will normalize the casing to cement thickness ratio by validating and proposing a simple mathematical calculation for establishing this ratio. Our calculations have shown that in the case of slimhole well concept, the thin cement sheath cannot serve as a strong well barrier as defined by current standards, and thus a new solution might be necessary. The second part will look at current new trends in wellbore construction that include external casing packers and other solutions such as metallic wellbore isolation solutions. Hydraulically expanded metal packers are a robust and reliable alternative to cement. They are each mounted to a casing joint and can be rotated while running in hole. They have a proven deployment track record of high diametrical expansion, conforming to the wellbore geometry, while isolating differential pressures more than 15,000psi. Exploration of load carrying capabilities will be completed using Finite Element Analysis (FEA), simulating the different well scenarios as described in the previous paragraph. This will enable us to establish which well types can use this novel technology for the replacement of cement. The paper will conclude with one possible solution that could be used to mitigate cement problems by shifting the well construction concept to a cementless new era. Also, understanding that the cement manufacturing process is highly CO2 intensive, emissions per well could be reduced through the newly proposed concept.
{"title":"Cementless Well Construction Opens the Full Control on Well Integrity for the Life of the Well","authors":"C. Teodoriu, O. Bello, R. Vasquez, Ryan M. Melander, Yosafat Esquitin","doi":"10.2118/206052-ms","DOIUrl":"https://doi.org/10.2118/206052-ms","url":null,"abstract":"\u0000 Well construction has relied on two main elements, casing and cement, to achieve the well goals while maintaining the highest possible well integrity. Can cementless well construction achieve similar goals? This paper is investigating the various well construction concepts proposed over the years and will analyze the cement's ability to withstand long term well loads.\u0000 First, a review of various well construction concepts such as slimhole, conventional, pre-salt and horizontal wells. We will normalize the casing to cement thickness ratio by validating and proposing a simple mathematical calculation for establishing this ratio. Our calculations have shown that in the case of slimhole well concept, the thin cement sheath cannot serve as a strong well barrier as defined by current standards, and thus a new solution might be necessary.\u0000 The second part will look at current new trends in wellbore construction that include external casing packers and other solutions such as metallic wellbore isolation solutions. Hydraulically expanded metal packers are a robust and reliable alternative to cement. They are each mounted to a casing joint and can be rotated while running in hole. They have a proven deployment track record of high diametrical expansion, conforming to the wellbore geometry, while isolating differential pressures more than 15,000psi. Exploration of load carrying capabilities will be completed using Finite Element Analysis (FEA), simulating the different well scenarios as described in the previous paragraph. This will enable us to establish which well types can use this novel technology for the replacement of cement.\u0000 The paper will conclude with one possible solution that could be used to mitigate cement problems by shifting the well construction concept to a cementless new era. Also, understanding that the cement manufacturing process is highly CO2 intensive, emissions per well could be reduced through the newly proposed concept.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"90 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81464242","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}
Chelating agents are used to stimulate high-temperature carbonate reservoirs and remove mineral scales. For field applications, commercial chelates—EDTA, DTPA, GLDA, etc.—are commonly supplied as 35–50 wt% (1.2–1.7 M) solutions and diluted two times in water. However, the dependence of the reaction rate on the concentration of chelate in solution has never been quantified. This paper focuses on determining the kinetics of calcite dissolution as a function of the dilution factor of commonly used chelates at acidic pH. Using a rotating disk apparatus, the kinetics of calcite marble dissolution in 0.1–0.25 M EDTA (pH=4.9–5.0), 0.1–0.25 M DTPA (pH=3.5–5.0), and 0.28–0.85 M GLDA (pH=3.7–5.0) solutions has been investigated. The dissolution of calcite in all chelates has a negative fractional-order that increases with temperature in the range -0.6 < n < -1.9. Thus, less concentrated chelate solutions react faster with calcite, and the effect of chelate dilution becomes less pronounced with a temperature increase. For example, three times dilution of pH≈3.7 commercial GLDA solution—from commonly used 50 vol% (0.85 M) to 16.7 vol% (0.28 M)—increases calcite dissolution rate 8.4, 4.9, 2.7, and 2.0 times at 98.6, 116.6, 134.6, and 188.6°F, respectively. Dilution of pH=5.0 EDTA and pH=3.5 DTPA from 0.25 M to 0.1 M increases the dissolution rate of calcite 1.4–3.1 times at 98.6–188.6°F. Probable reasons for such an unusual reaction behavior are discussed in the paper. Presented results are integral for designing the stimulation operations in carbonate reservoir rocks and the removal of carbonate scales.
螯合剂用于刺激高温碳酸盐储层，去除矿物结垢。对于现场应用，商业螯合物- edta, DTPA, GLDA等-通常以35-50 wt% (1.2-1.7 M)的溶液提供，并在水中稀释两倍。然而，反应速率对溶液中螯合物浓度的依赖性从未被量化。本文重点研究了在酸性pH下方解石溶解动力学与常用螯合物稀释系数的关系。利用旋转圆盘装置，研究了方解石大理岩在0.1-0.25 M EDTA (pH= 4.9-5.0)、0.1-0.25 M DTPA (pH= 3.5-5.0)和0.28-0.85 M GLDA (pH= 3.7-5.0)溶液中的溶解动力学。在-0.6 < n < -1.9范围内，方解石在所有螯合物中的溶解均呈负分数阶，随温度的升高而增加。因此，浓度较低的螯合剂溶液与方解石反应更快，并且随着温度的升高，螯合剂稀释的效果变得不那么明显。例如，将pH≈3.7的商业GLDA溶液稀释三倍，从常用的50 vol% (0.85 M)稀释到16.7 vol% (0.28 M)，在98.6、116.6、134.6和188.6°F下，方解石溶解率分别增加8.4、4.9、2.7和2.0倍。当pH=5.0 EDTA和pH=3.5 DTPA从0.25 M稀释到0.1 M时，方解石的溶解率提高了1.4-3.1倍，温度为98.6-188.6°F。本文讨论了这种不寻常反应行为的可能原因。所得结果对设计碳酸盐岩储层增产作业和去除碳酸盐岩结垢具有重要意义。
{"title":"Chelating Agents as a Stimulation Fluid with a Negative Reaction Order: More Diluted Solutions React Faster with Carbonates","authors":"Igor B. Ivanishin, H. Samouei","doi":"10.2118/206376-ms","DOIUrl":"https://doi.org/10.2118/206376-ms","url":null,"abstract":"\u0000 Chelating agents are used to stimulate high-temperature carbonate reservoirs and remove mineral scales. For field applications, commercial chelates—EDTA, DTPA, GLDA, etc.—are commonly supplied as 35–50 wt% (1.2–1.7 M) solutions and diluted two times in water. However, the dependence of the reaction rate on the concentration of chelate in solution has never been quantified. This paper focuses on determining the kinetics of calcite dissolution as a function of the dilution factor of commonly used chelates at acidic pH. Using a rotating disk apparatus, the kinetics of calcite marble dissolution in 0.1–0.25 M EDTA (pH=4.9–5.0), 0.1–0.25 M DTPA (pH=3.5–5.0), and 0.28–0.85 M GLDA (pH=3.7–5.0) solutions has been investigated. The dissolution of calcite in all chelates has a negative fractional-order that increases with temperature in the range -0.6 < n < -1.9. Thus, less concentrated chelate solutions react faster with calcite, and the effect of chelate dilution becomes less pronounced with a temperature increase. For example, three times dilution of pH≈3.7 commercial GLDA solution—from commonly used 50 vol% (0.85 M) to 16.7 vol% (0.28 M)—increases calcite dissolution rate 8.4, 4.9, 2.7, and 2.0 times at 98.6, 116.6, 134.6, and 188.6°F, respectively. Dilution of pH=5.0 EDTA and pH=3.5 DTPA from 0.25 M to 0.1 M increases the dissolution rate of calcite 1.4–3.1 times at 98.6–188.6°F. Probable reasons for such an unusual reaction behavior are discussed in the paper. Presented results are integral for designing the stimulation operations in carbonate reservoir rocks and the removal of carbonate scales.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"174 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76455264","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}
Technological advances unveil a dual reality in the oil and gas Industry. On one hand, the benefits of blockchain and artificial intelligence (AI), among others, has arrived to revolutionize the industry. On the other hand, industry professionals remain trapped in bureaucratic processes that undermine their performance. The diagnosis: knowledge workers, responsible for optimizing the recovery and economic performance of the fields, are the missing link in the digital transformation chain. They are suffering the digitalization of the status quo. This paper puts forward a broad digital transformation framework designed to increase the knowledge worker's productivity. Digital transformation is not just about the implementation and use of cutting-edge technologies. It is also the response to digital trends, and about adopting new processes and redesigning existing ones to compete effectively in an increasingly digital world. Prioritizing technology as the ultimate goal puts the business processes and the knowledge workers aside from the discussion. The key to this proposal is rethinking the business model according to the possibilities of new technologies based on a six-dimension scheme:Corporate strategy: It defines the long-term vision and investment criteria for value creation. Technology is an element within a business scheme that should not be analyzed in isolation.Digital strategy: Within the corporate strategy, what operational and strategic role does technology play? Should it only support the company's operation, or should it drive strategic reinvention?Culture: While digital transformation is the company's response to digital trends, culture is the muscle that provides (or not) the attributes required to succeed in this transformation endeavor. Innovation and creativity should be promoted as part of the company's DNA.Knowledge processes: A business model, built on new technologies, will necessarily impose new and automated practices. While the automation of physical processes is a fact, the automation of knowledge processes is the weakest link.Data governance: It defines the necessary conditions that guarantee the quality of the information and its strategic acquisition. Two elements are a must: the automation of processes, thereby avoiding arbitrariness in data management; and centralized databases, thereby eliminating data duplicity and criteria discrepancy.Data Science: At this point in the model, the company has efficient, automatic, and fast processes, assuring the quality and availability of the data from its conception to the final storage. Then, data scientists will have all the means, and a clear and aligned vision (corporate strategy) to extract meaningful insights for the business.
{"title":"The Digital Transformation of the Knowledge Worker","authors":"Fernando Luis Creus","doi":"10.2118/205879-ms","DOIUrl":"https://doi.org/10.2118/205879-ms","url":null,"abstract":"\u0000 Technological advances unveil a dual reality in the oil and gas Industry. On one hand, the benefits of blockchain and artificial intelligence (AI), among others, has arrived to revolutionize the industry. On the other hand, industry professionals remain trapped in bureaucratic processes that undermine their performance. The diagnosis: knowledge workers, responsible for optimizing the recovery and economic performance of the fields, are the missing link in the digital transformation chain. They are suffering the digitalization of the status quo.\u0000 This paper puts forward a broad digital transformation framework designed to increase the knowledge worker's productivity. Digital transformation is not just about the implementation and use of cutting-edge technologies. It is also the response to digital trends, and about adopting new processes and redesigning existing ones to compete effectively in an increasingly digital world. Prioritizing technology as the ultimate goal puts the business processes and the knowledge workers aside from the discussion.\u0000 The key to this proposal is rethinking the business model according to the possibilities of new technologies based on a six-dimension scheme:Corporate strategy: It defines the long-term vision and investment criteria for value creation. Technology is an element within a business scheme that should not be analyzed in isolation.Digital strategy: Within the corporate strategy, what operational and strategic role does technology play? Should it only support the company's operation, or should it drive strategic reinvention?Culture: While digital transformation is the company's response to digital trends, culture is the muscle that provides (or not) the attributes required to succeed in this transformation endeavor. Innovation and creativity should be promoted as part of the company's DNA.Knowledge processes: A business model, built on new technologies, will necessarily impose new and automated practices. While the automation of physical processes is a fact, the automation of knowledge processes is the weakest link.Data governance: It defines the necessary conditions that guarantee the quality of the information and its strategic acquisition. Two elements are a must: the automation of processes, thereby avoiding arbitrariness in data management; and centralized databases, thereby eliminating data duplicity and criteria discrepancy.Data Science: At this point in the model, the company has efficient, automatic, and fast processes, assuring the quality and availability of the data from its conception to the final storage. Then, data scientists will have all the means, and a clear and aligned vision (corporate strategy) to extract meaningful insights for the business.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"70 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77713766","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}
Tortuosity is one of the critical factors to be considered for complex directional well trajectories, complicated build rates, precise steering in thin reservoirs, and extended reach wells. This paper discusses the pitfalls of estimating tortuosity to quantify borehole quality and answers questions, such as whether the claimed benefits (i.e., enhanced drilling performance, improved hole cleaning, ease of running casing, and superior cement operations) can be fully attributed to reduced borehole tortuosity. Running casing may mask the tortuosity present in the as drilled open hole wellbore section. This vanishing tortuosity alters the apparent "wellbore quality" and the new tortuosity representative of the cased hole path may present new appearing tortuosity. Both vanishing and appearing tortuosity are generally neglected in engineering calculations. Conventional methods to calculate tortuosity are based on the predetermined shape of the trajectory using the minimum curvature method. Wellbore undulation (geometrical tortuosity) is determined using geometrical measurements such as inclination, azimuth, and calculated displacement; however, much of this wellbore undulation vanishes after the casing is run, and thus the cased off wellpath appears smoother. This apparent change in wellbore tortuosity results from the flexural stiffness and rigidity of the casing pipes, and the compression and tension loads along the length of the casing string. Acquiring a subsequent survey along the cased well path yields new inclinations, azimuths, and displacements. This new survey records wellpath undulations resulting from the casings path through the original open hole wellbore geometry and what we call tubular undulation (mechanical tortuosity) which is specific to the path and position of the casing within the wellbore. The smoothing of the wellpath resulting from the casing masking original wellbore tortuosity results in the original geometrical tortuosity vanishing while the new undulations resulting from the mechanical tortuosity of the casing causes additional tortuosity to appear. The comparison between the geometrical and mechanical tortuosity provides a method of quantifying the vanishing and appearing tortuosity.
{"title":"Mechanical and Geometrical Tortuosities: Vanishing and Appearing Tortuosities","authors":"Robello Samuel, J. Lightfoot, W. Turner","doi":"10.2118/206188-ms","DOIUrl":"https://doi.org/10.2118/206188-ms","url":null,"abstract":"\u0000 Tortuosity is one of the critical factors to be considered for complex directional well trajectories, complicated build rates, precise steering in thin reservoirs, and extended reach wells. This paper discusses the pitfalls of estimating tortuosity to quantify borehole quality and answers questions, such as whether the claimed benefits (i.e., enhanced drilling performance, improved hole cleaning, ease of running casing, and superior cement operations) can be fully attributed to reduced borehole tortuosity. Running casing may mask the tortuosity present in the as drilled open hole wellbore section. This vanishing tortuosity alters the apparent \"wellbore quality\" and the new tortuosity representative of the cased hole path may present new appearing tortuosity. Both vanishing and appearing tortuosity are generally neglected in engineering calculations.\u0000 Conventional methods to calculate tortuosity are based on the predetermined shape of the trajectory using the minimum curvature method. Wellbore undulation (geometrical tortuosity) is determined using geometrical measurements such as inclination, azimuth, and calculated displacement; however, much of this wellbore undulation vanishes after the casing is run, and thus the cased off wellpath appears smoother. This apparent change in wellbore tortuosity results from the flexural stiffness and rigidity of the casing pipes, and the compression and tension loads along the length of the casing string. Acquiring a subsequent survey along the cased well path yields new inclinations, azimuths, and displacements. This new survey records wellpath undulations resulting from the casings path through the original open hole wellbore geometry and what we call tubular undulation (mechanical tortuosity) which is specific to the path and position of the casing within the wellbore. The smoothing of the wellpath resulting from the casing masking original wellbore tortuosity results in the original geometrical tortuosity vanishing while the new undulations resulting from the mechanical tortuosity of the casing causes additional tortuosity to appear. The comparison between the geometrical and mechanical tortuosity provides a method of quantifying the vanishing and appearing tortuosity.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"138 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75958280","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}
O. Ogolo, P. Nzerem, I. Okafor, Raji Abubakar, M. Mahmoud, George Kalu
Globally, there are two types of petroleum fiscal system; the concessionary and the contractual petroleum fiscal system. The main differences between the two types of petroleum fiscal system is the ownership of the resources and some distinct fiscal terms. The contractual petroleum fiscal system specifies a cost recovery option and profit oil split unlike the concessionary petroleum fiscal system that allows the contractor to recoup his capital before payment of tax. This tends to increase the risk associated with the host government revenue as investment in the production of hydrocarbon is filled with uncertainties. There is a need to redesign the concessionary petroleum fiscal to enable it reduce the risk associated with the host government revenue by making the host government to earn revenue early from petroleum investment. This research therefore evaluated a hybrid petroleum fiscal system for investment in the exploration and production of hydrocarbon. The concessionary petroleum fiscal system was adjusted to include a cost recovery option. Petroleum economic model for investment in a typical onshore oil field was built using spreadsheet modelling technique with the fiscal terms in the hybrid petroleum fiscal system embedded in it. The cost recovery option and oil price in the model were varied between 0-100% and $20-$100 per barrel. The NCF, IRR and payout period of the investment were determined. It was observed that the lower the cost recovery option, the higher the host government revenue. From the profitability analysis of the investment in the hybrid petroleum fiscal system, it was observed that when the price of oil was $100/bbl, the NCF of the host government was $9146 and $8426.3 for 0% and 80% cost recovery option. The lower the cost recovery option, the higher the payout period and the lower the internal rate of return. Though lower cost recovery increased the host government revenue more but it may make the hybrid petroleum fiscal system unattractive for investment in periods of low oil price. Hence a higher cost recovery option was recommended for the use of this type of petroleum fiscal system.
{"title":"A Hybrid Petroleum Fiscal System for Investment in the Exploration and Production E&P of Hydrocarbon","authors":"O. Ogolo, P. Nzerem, I. Okafor, Raji Abubakar, M. Mahmoud, George Kalu","doi":"10.2118/206349-ms","DOIUrl":"https://doi.org/10.2118/206349-ms","url":null,"abstract":"\u0000 Globally, there are two types of petroleum fiscal system; the concessionary and the contractual petroleum fiscal system. The main differences between the two types of petroleum fiscal system is the ownership of the resources and some distinct fiscal terms. The contractual petroleum fiscal system specifies a cost recovery option and profit oil split unlike the concessionary petroleum fiscal system that allows the contractor to recoup his capital before payment of tax. This tends to increase the risk associated with the host government revenue as investment in the production of hydrocarbon is filled with uncertainties. There is a need to redesign the concessionary petroleum fiscal to enable it reduce the risk associated with the host government revenue by making the host government to earn revenue early from petroleum investment. This research therefore evaluated a hybrid petroleum fiscal system for investment in the exploration and production of hydrocarbon. The concessionary petroleum fiscal system was adjusted to include a cost recovery option. Petroleum economic model for investment in a typical onshore oil field was built using spreadsheet modelling technique with the fiscal terms in the hybrid petroleum fiscal system embedded in it. The cost recovery option and oil price in the model were varied between 0-100% and $20-$100 per barrel. The NCF, IRR and payout period of the investment were determined. It was observed that the lower the cost recovery option, the higher the host government revenue. From the profitability analysis of the investment in the hybrid petroleum fiscal system, it was observed that when the price of oil was $100/bbl, the NCF of the host government was $9146 and $8426.3 for 0% and 80% cost recovery option. The lower the cost recovery option, the higher the payout period and the lower the internal rate of return. Though lower cost recovery increased the host government revenue more but it may make the hybrid petroleum fiscal system unattractive for investment in periods of low oil price. Hence a higher cost recovery option was recommended for the use of this type of petroleum fiscal system.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73874805","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}
Pradeep T. Pillai, Chih-Cheng Lin, J. Brege, R. Mohan, E. Derkach, V. Lafitte, B. Gadiyar, Tint Htoo Aung, J. Santamaría
For offshore wells requiring sand control, Open Hole Gravel Packing (OHGP) with or without shunted screen technology is a common completion technique. Prior to this paper, there has been no application of shunted screen OHGP in High-Pressure High-Temperature (HPHT) environment due to lack of a viscous fluid availability in high-density divalent brines (> 14.6 lbm/U.S. gal). For the case study, the fluid requirements in terms of density and temperature were 15.4 lbm/U.S. gal and 265°F, respectively. The only brine option at this density was a blend of calcium chloride/bromide and zinc bromide. In this brine and density, none of the existing fluids work hence a novel polymer-based fluid had to be developed. The fluid had to pass the following tests a) rheology before and after subjecting to high shear of both uncontaminated and contaminated fluids at 3 different temperatures b) sand settling tests at 4 different temperatures c) Production Screen Tester to ensure the fluid does not plug the screens during the job. System Integration Tests (SIT) were performed to ensure the mixing equipment would be able to batch mix the fluid and actual pumping equipment would function properly with the fluid. The field trial planning included simulations, pre-job meetings, and fluid management plan. The job was executed as per the procedure outlined during pre-job meetings. This paper discusses laboratory development, yard test qualification, and successful shunted screen OHGP case history of a novel 15.4 lbm/U.S. gal viscous gravel pack carrier fluid.
{"title":"Industry First Openhole Alternate Path Gravel Pack Completion in HPHT Environment: Fluid Development and Case History","authors":"Pradeep T. Pillai, Chih-Cheng Lin, J. Brege, R. Mohan, E. Derkach, V. Lafitte, B. Gadiyar, Tint Htoo Aung, J. Santamaría","doi":"10.2118/206048-ms","DOIUrl":"https://doi.org/10.2118/206048-ms","url":null,"abstract":"\u0000 For offshore wells requiring sand control, Open Hole Gravel Packing (OHGP) with or without shunted screen technology is a common completion technique. Prior to this paper, there has been no application of shunted screen OHGP in High-Pressure High-Temperature (HPHT) environment due to lack of a viscous fluid availability in high-density divalent brines (> 14.6 lbm/U.S. gal).\u0000 For the case study, the fluid requirements in terms of density and temperature were 15.4 lbm/U.S. gal and 265°F, respectively. The only brine option at this density was a blend of calcium chloride/bromide and zinc bromide. In this brine and density, none of the existing fluids work hence a novel polymer-based fluid had to be developed. The fluid had to pass the following tests a) rheology before and after subjecting to high shear of both uncontaminated and contaminated fluids at 3 different temperatures b) sand settling tests at 4 different temperatures c) Production Screen Tester to ensure the fluid does not plug the screens during the job. System Integration Tests (SIT) were performed to ensure the mixing equipment would be able to batch mix the fluid and actual pumping equipment would function properly with the fluid. The field trial planning included simulations, pre-job meetings, and fluid management plan. The job was executed as per the procedure outlined during pre-job meetings.\u0000 This paper discusses laboratory development, yard test qualification, and successful shunted screen OHGP case history of a novel 15.4 lbm/U.S. gal viscous gravel pack carrier fluid.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"233 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80857479","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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