Remote gas wells unloading and remote field well testing becomes more challenging because of H.S.E. hazards and cost-saving. This process adds to environmental footprint concerns in the oil and gas industry. Also, government laws and restrictions become one of the main stoppers for this process that could deviate the project from safe operating status by introducing new risks and hazards. This paper introduces two cases related to oil and gas flaring. In the first case, the high-pressure gas wells uploading within the remote area requires high-pressure equipment and high-pressure pumps that suit condensate pumping; some availability issues hurdle this operation in many countries. Adding to that, the high-cost addition faces the planning operation when renting the special equipment needed. Alternative condensate flaring is considered nowadays forbidden in most countries' regulations and laws. Innovative practices and equipment modifications were built and applied to secure both environment and cost. In this method, the sound power is utilized after the unloading and testing to circulate the condensate from the tanks to the separator with a low-pressure pump then divert well flow to the division and the pipeline. The process reduces condensate pumping risk, and zero flaring were achieved. More than 3000 bbls of condensate were circulated monthly to the gas facility without affecting the operation procedures. The company applied this process to all testing equipment and considered it in the new contracts as a technical acceptance factor. Therefore, hazardous waste was reduced, emissions decreased, and safer operation is guaranteed for workers was observed. In the second case, the remote field requires a strong appraisal program, including long-term production and injection tests; meanwhile, interference between wells adds essential value before proceeding with the entire field development plan. This work presents a successful and valuable case supporting technical team decisions while considering H.S.E. as a priority. A field case study discussed in this paper presented the reduction of condensate trucking risk and achieved zero oil flaring. Sixty thousand bbls of light oil were injected safely within two months long term test to the same producer. An injectivity test for another reservoir was conducted without additional cost and without affecting the operation procedures. Besides the above-stated advantages of applying the new process in both cases, this process also can work in the high pressure and risky wills. Therefore, guaranteeing zero flaring and ensuring a lower carbon footprint while supporting the third corner of H.S.E., the environment while saving costs, can always be achieved.
{"title":"Zero Condensate Flaring Utilizing Well Power and Equipment Modifications","authors":"G. M. Saad","doi":"10.2118/207654-ms","DOIUrl":"https://doi.org/10.2118/207654-ms","url":null,"abstract":"\u0000 Remote gas wells unloading and remote field well testing becomes more challenging because of H.S.E. hazards and cost-saving. This process adds to environmental footprint concerns in the oil and gas industry. Also, government laws and restrictions become one of the main stoppers for this process that could deviate the project from safe operating status by introducing new risks and hazards.\u0000 This paper introduces two cases related to oil and gas flaring. In the first case, the high-pressure gas wells uploading within the remote area requires high-pressure equipment and high-pressure pumps that suit condensate pumping; some availability issues hurdle this operation in many countries. Adding to that, the high-cost addition faces the planning operation when renting the special equipment needed. Alternative condensate flaring is considered nowadays forbidden in most countries' regulations and laws. Innovative practices and equipment modifications were built and applied to secure both environment and cost. In this method, the sound power is utilized after the unloading and testing to circulate the condensate from the tanks to the separator with a low-pressure pump then divert well flow to the division and the pipeline.\u0000 The process reduces condensate pumping risk, and zero flaring were achieved. More than 3000 bbls of condensate were circulated monthly to the gas facility without affecting the operation procedures. The company applied this process to all testing equipment and considered it in the new contracts as a technical acceptance factor. Therefore, hazardous waste was reduced, emissions decreased, and safer operation is guaranteed for workers was observed.\u0000 In the second case, the remote field requires a strong appraisal program, including long-term production and injection tests; meanwhile, interference between wells adds essential value before proceeding with the entire field development plan. This work presents a successful and valuable case supporting technical team decisions while considering H.S.E. as a priority.\u0000 A field case study discussed in this paper presented the reduction of condensate trucking risk and achieved zero oil flaring. Sixty thousand bbls of light oil were injected safely within two months long term test to the same producer. An injectivity test for another reservoir was conducted without additional cost and without affecting the operation procedures.\u0000 Besides the above-stated advantages of applying the new process in both cases, this process also can work in the high pressure and risky wills. Therefore, guaranteeing zero flaring and ensuring a lower carbon footprint while supporting the third corner of H.S.E., the environment while saving costs, can always be achieved.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85104197","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. Breislin, L. Galluccio, Kate Al Tameemi, Riaz Khan, A. Abdelaal
Understanding reservoir architecture is key to comprehend the distribution of reservoir quality when evaluating a field's prospectivity. Renewed interest in the tight, gas-rich Middle Miocene anhydrite intervals (Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6) by ADNOC has given new impetus to improving its reservoir characterisation. In this context, this study provides valuable new insights in geological knowledge at the field scale within a formation with limited existing studies. From a sedimentological point of view, the anhydrite layers of the Miocene Formation, Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6 (which comprise three stacked sequences: Bur1, Bur2 and Bur3; Hardenbol et al., 1998), have comparable depositional organisation throughout the study area. Bur1 and Bur2 are characterised by an upward transition from intertidal-dominated deposits to low-energy inner ramp-dominated sedimentation displaying reasonably consistent thickness across the area. Bur3 deposits imply an initial upward deepening from an argillaceous intertidal-dominated to an argillaceous subtidal-dominated setting, followed by an upward shallowing into intertidal and supratidal sabkha-dominated environments. This Bur3 cycle thickens towards the south-east due to a possible deepening, resulting in the subtle increase in thickness of the subtidal and intertidal deposits occurring around the maximum-flooding surface. The interbedded relationship between the thin limestone and anhydrite layers within the intertidal and proximal inner ramp deposits impart strong permeability anisotropy, with the anhydrite acting as significant baffles to vertical fluid flow. A qualitative reservoir quality analysis, combining core sedimentology data from 10 wells, 331 CCA data points, 58 thin-sections and 10 SEM samples has identified that reservoir layers Anh-4 and Anh-6 contain the best porosity and permeability values, with the carbonate facies of the argillaceous-prone intertidal and distal inner ramp deposits hosting the best reservoir potential. Within these facies, the pore systems within the carbonate facies are impacted by varying degrees of dolomitisation and dissolution which enhance the pore system, and cementation (anhydrite and calcite), which degrade the pore system. The combination of these diagenetic phases results in the wide spread of porosity and permeability data observed. The integration of both the sedimentological features and diagenetic overprint of the Middle Miocene anhydrite intervals shows the fundamental role played by the depositional environment in its reservoir architecture. This study has revealed the carbonate-dominated depositional environment groups within the anhydrite stratigraphic layers likely host both the best storage capacity and flow potential. Within these carbonate-dominated layers, the thicker, homogenous carbonate deposits would be more conducive to vertical and lateral flow than thinner interbedded carbonates and anhydrites, which may present as baffl
在评价油田远景时，了解储层构型是了解储层质量分布的关键。ADNOC对中中新世致密、富气硬泥岩层段(Anh-1、Anh-2、Anh-3、Anh-4和Anh-6)的重新关注，为改善其储层特征提供了新的动力。在此背景下，该研究在现有研究有限的情况下，为地层的野外地质知识提供了有价值的新见解。从沉积学角度看，中新世组Anh-1、Anh-2、Anh-3、Anh-4和Anh-6(由Bur1、Bur2和Bur3三个叠置层序组成;Hardenbol et al.， 1998)在整个研究区域都有类似的沉积组织。Bur1和Bur2的特征是由潮间带为主的沉积向上过渡到低能量的内斜坡为主的沉积，整个地区的厚度相当一致。Bur3沉积预示着从泥质潮间带为主到泥质潮下带为主的初始向上深化，随后向上浅化进入潮间带和潮上沙布哈为主的环境。由于可能加深，这个Bur3旋回向东南方向变厚，导致最大洪水面周围的潮下和潮间沉积物的厚度略有增加。潮间带和近端内斜坡沉积中薄灰岩与硬石膏层的互层关系赋予了较强的渗透率各向异性，硬石膏对垂向流体流动起着重要的阻碍作用。通过对10口井的岩心沉积学数据、331个CCA数据点、58个薄片和10个SEM样品进行定性储层质量分析，确定了安四层和安六层储层具有最佳的孔隙度和渗透率值，其中倾向泥质潮间带和远端内斜坡沉积的碳酸盐相具有最佳的储层潜力。在这些相中，碳酸盐相的孔隙系统受到不同程度的白云化作用和溶蚀作用的影响，这些作用增强了孔隙系统，而胶结作用(硬石膏和方解石)则降低了孔隙系统。这些成岩相的组合导致观察到的孔隙度和渗透率数据分布广泛。中中新世硬石膏层段的沉积学特征和成岩覆层综合反映了沉积环境对储层构型的根本影响。研究表明，硬石膏地层中以碳酸盐岩为主的沉积环境群可能具有最佳的储集能力和流动潜力。在这些以碳酸盐为主的地层中，较厚的均质碳酸盐沉积物比较薄的互层碳酸盐和硬石膏更有利于垂直和横向流动，这可能成为垂直流动的障碍或障碍，并产生显著的渗透率各向异性。
{"title":"Reservoir Quality of the Miocene Formation Gas Deposits, Onshore Abu Dhabi","authors":"C. Breislin, L. Galluccio, Kate Al Tameemi, Riaz Khan, A. Abdelaal","doi":"10.2118/207508-ms","DOIUrl":"https://doi.org/10.2118/207508-ms","url":null,"abstract":"\u0000 Understanding reservoir architecture is key to comprehend the distribution of reservoir quality when evaluating a field's prospectivity. Renewed interest in the tight, gas-rich Middle Miocene anhydrite intervals (Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6) by ADNOC has given new impetus to improving its reservoir characterisation. In this context, this study provides valuable new insights in geological knowledge at the field scale within a formation with limited existing studies.\u0000 From a sedimentological point of view, the anhydrite layers of the Miocene Formation, Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6 (which comprise three stacked sequences: Bur1, Bur2 and Bur3; Hardenbol et al., 1998), have comparable depositional organisation throughout the study area. Bur1 and Bur2 are characterised by an upward transition from intertidal-dominated deposits to low-energy inner ramp-dominated sedimentation displaying reasonably consistent thickness across the area. Bur3 deposits imply an initial upward deepening from an argillaceous intertidal-dominated to an argillaceous subtidal-dominated setting, followed by an upward shallowing into intertidal and supratidal sabkha-dominated environments. This Bur3 cycle thickens towards the south-east due to a possible deepening, resulting in the subtle increase in thickness of the subtidal and intertidal deposits occurring around the maximum-flooding surface. The interbedded relationship between the thin limestone and anhydrite layers within the intertidal and proximal inner ramp deposits impart strong permeability anisotropy, with the anhydrite acting as significant baffles to vertical fluid flow.\u0000 A qualitative reservoir quality analysis, combining core sedimentology data from 10 wells, 331 CCA data points, 58 thin-sections and 10 SEM samples has identified that reservoir layers Anh-4 and Anh-6 contain the best porosity and permeability values, with the carbonate facies of the argillaceous-prone intertidal and distal inner ramp deposits hosting the best reservoir potential. Within these facies, the pore systems within the carbonate facies are impacted by varying degrees of dolomitisation and dissolution which enhance the pore system, and cementation (anhydrite and calcite), which degrade the pore system. The combination of these diagenetic phases results in the wide spread of porosity and permeability data observed.\u0000 The integration of both the sedimentological features and diagenetic overprint of the Middle Miocene anhydrite intervals shows the fundamental role played by the depositional environment in its reservoir architecture. This study has revealed the carbonate-dominated depositional environment groups within the anhydrite stratigraphic layers likely host both the best storage capacity and flow potential. Within these carbonate-dominated layers, the thicker, homogenous carbonate deposits would be more conducive to vertical and lateral flow than thinner interbedded carbonates and anhydrites, which may present as baffl","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"87 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90055663","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. Torre, Analyn Azancot, Fabián Florez, Weifu Zhou
This paper presents a structured methodology for an oil company to embark on a digital transformation. It was implemented in several JVs with a NOC that includes three producing blocks with dozens of mature fields. The methodology has several key unique strengths: One is the ability to isolate the core-money-making processes and build a digital strategy around them. This shows early gains and at the same time becomes a buy-in support for management. Another advantage is the simplicity to define the "desired" digital maturity level using direct input from the final stakeholders. This is achieved by using the process enhancement method, a SIPOC technique (Supplier, Input, Process, Output, Customer analysis). Also, an important strength is the methodology does not ignore the existing IT infrastructure, nor the field systems (i.e., SCADA) and re-uses them, as much as possible, giving enough time for a transition or an upgrade when needed. Several tools are provided in this paper that makes the methodology consistent, auditable, and strong to support the designed digital strategy to any management level with high chance of approval. The methodology is flexible enough to be run on various types of contracts, hydrocarbon phase or operational environments. As with any method, it relies on commitment from the top and base line in the organization, requiring open and honest evaluation of current inefficiencies and, equally important, resources (budget and people). In summary, a digital transformation is not a sudden leap from a company's current analog status to an instantaneous digital state of being. Rather, it is a progressive, step-by-step transition of core processes and user-centric workflows that requires careful planning and a thoughtful methodology to find the most suitable scenario for each company.
{"title":"Assess Digital Maturity to Set Digital Transformation Strategy in Oil and Gas","authors":"M. Torre, Analyn Azancot, Fabián Florez, Weifu Zhou","doi":"10.2118/207968-ms","DOIUrl":"https://doi.org/10.2118/207968-ms","url":null,"abstract":"\u0000 This paper presents a structured methodology for an oil company to embark on a digital transformation. It was implemented in several JVs with a NOC that includes three producing blocks with dozens of mature fields.\u0000 The methodology has several key unique strengths: One is the ability to isolate the core-money-making processes and build a digital strategy around them. This shows early gains and at the same time becomes a buy-in support for management. Another advantage is the simplicity to define the \"desired\" digital maturity level using direct input from the final stakeholders. This is achieved by using the process enhancement method, a SIPOC technique (Supplier, Input, Process, Output, Customer analysis). Also, an important strength is the methodology does not ignore the existing IT infrastructure, nor the field systems (i.e., SCADA) and re-uses them, as much as possible, giving enough time for a transition or an upgrade when needed.\u0000 Several tools are provided in this paper that makes the methodology consistent, auditable, and strong to support the designed digital strategy to any management level with high chance of approval. The methodology is flexible enough to be run on various types of contracts, hydrocarbon phase or operational environments.\u0000 As with any method, it relies on commitment from the top and base line in the organization, requiring open and honest evaluation of current inefficiencies and, equally important, resources (budget and people).\u0000 In summary, a digital transformation is not a sudden leap from a company's current analog status to an instantaneous digital state of being. Rather, it is a progressive, step-by-step transition of core processes and user-centric workflows that requires careful planning and a thoughtful methodology to find the most suitable scenario for each company.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90555870","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Gadelhak, A. Yugay, G. Pimenta, Adeel Allah Bux, M. Baslaib, A. Jaiyeola, Yohannes Pangesto, Diaa Yassien, Mohamed Al-Badi, Mubashir Ahmed, Noora Al-Mahri, R. Reddy, Bashar Al-Eid, Niraj Kumar
Gas wells with Carbon steel completion, Can it handle sour Gas production, Case Study. It is a successful case of producing sour gas (up to 18% H2S and 9.2% CO2) since 2016 wells with carbon steel tubing with maintaining downhole chemical injection of corrosion inhibitor. During 2014 a group of new wells has been drilled in X giant onshore gas reservoir under ADNOC onshore company operating area to maximize gas production and to meet production mandate. Majority of wells has been drilled within the North and peripheral Area of the reservoir. All wells has been completed with a standard completion with a Top completion (+/-7000 ft.) in carbon steel with downhole chemical injection valve, and a corrosion resistant alloy section below the CIV. After wells commissioning, high H2S contents were observed (Up to 18%), and Management initially instructed operations to shut in 9 wells and formulated a task force to study the applicable options and analyze the data to ensure asset integrity. The TF recommendation was to flow the wells with close monitoring of wells integrity, in particular annulus pressure A comprehensive downhole exercise has been done by Carbon steel completion with downhole chemical injection is a validated completion solution for such conditions. Clearly, case is as a solid reference for sour gas production using conventional completion, sustaining Long-term production is adding more weight to the case conclusion.
{"title":"Gas Wells with Carbon Steel Completion, Can it Handle Sour Gas Production, Case Study","authors":"A. Gadelhak, A. Yugay, G. Pimenta, Adeel Allah Bux, M. Baslaib, A. Jaiyeola, Yohannes Pangesto, Diaa Yassien, Mohamed Al-Badi, Mubashir Ahmed, Noora Al-Mahri, R. Reddy, Bashar Al-Eid, Niraj Kumar","doi":"10.2118/208157-ms","DOIUrl":"https://doi.org/10.2118/208157-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Gas wells with Carbon steel completion, Can it handle sour Gas production, Case Study.\u0000 \u0000 \u0000 \u0000 It is a successful case of producing sour gas (up to 18% H2S and 9.2% CO2) since 2016 wells with carbon steel tubing with maintaining downhole chemical injection of corrosion inhibitor.\u0000 \u0000 \u0000 \u0000 During 2014 a group of new wells has been drilled in X giant onshore gas reservoir under ADNOC onshore company operating area to maximize gas production and to meet production mandate. Majority of wells has been drilled within the North and peripheral Area of the reservoir. All wells has been completed with a standard completion with a Top completion (+/-7000 ft.) in carbon steel with downhole chemical injection valve, and a corrosion resistant alloy section below the CIV.\u0000 After wells commissioning, high H2S contents were observed (Up to 18%), and Management initially instructed operations to shut in 9 wells and formulated a task force to study the applicable options and analyze the data to ensure asset integrity.\u0000 The TF recommendation was to flow the wells with close monitoring of wells integrity, in particular annulus pressure\u0000 A comprehensive downhole exercise has been done by\u0000 \u0000 \u0000 \u0000 Carbon steel completion with downhole chemical injection is a validated completion solution for such conditions.\u0000 \u0000 \u0000 \u0000 Clearly, case is as a solid reference for sour gas production using conventional completion, sustaining Long-term production is adding more weight to the case conclusion.\u0000","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88875417","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}
Ying Chun Guan, M. Rashaid, L. Hayat, Qasim Dashti, K. Sassi, H. Ayyad, Aisha Embaireeg, Radhika Patro, Sarah Alajmi, Laila Akbar, Abdullah Al Jamaan, Matthew Sullivan
The biggest clastic reservoir based in Kuwait has been facing evaluation challenges over the thick intervals of highly laminated thin hydrocarbon layers. Conventional wireline tools have a limitation on resolution when it comes to addressing these thin beds. Therefore, the reserves are usually underestimated, and thin pays are often overlooked. This paper presents the integration of a variety of advanced Wireline tools in order to correctly evaluate and compute reserves from these thin pay zones. Acquisition of the triaxial induction tool enabled the study of resistivity anisotropy and the identification of thin pay zones through the distinct reading of the resistivity of the thin sand reservoir. The thin layers have also been further validated using high resolution advanced thin bed analysis from image logs. Advanced spectroscopy and NMR data were used to quantitively define the sand and shale fractions within the thin beds. These measurements were critical to input to improve the resistivity interpretation followed by a reliable estimate of the saturation. High resolution dielectric measurements provided resistivity-independent saturation information enhancing the NMR interpretation using water-filled porosity which was a key input into the identification of the heavy oil presence in Burgan. The newly identified thin pay zones have been further validated using the fluid sampling confirming presence of hydrocarbons with greater understanding of its properties and uniquely quantifying the mobile fluid fractions. The additional available reserves can only be properly determined by combining data from multiple sources to achieve a comprehensive evaluation. Resistivity anisotropy was observed based on the separation of vertical and horizontal resistivities and was therefore investigated to understand its root-cause over different zones. By integrating the results from the dielectric dispersion measurements, the diffusion-based NMR data, spectroscopy data, borehole image interpretation and high-resolution sand count delineation of different lithologic units at a finer scale, we were able to identify thin bedded sand-shale intervals in addition to pin-pointing the heavy oil intervals. Hydrocarbon saturations of individual sand layers showed improvement in hydrocarbon volumes, improvement in permeabilities across the studied zones and increased net pay estimations by 12%. Results from the fluid sampling performed across the newly identified thin pays have validated the advanced logging interpretation results and the presence of hydrocarbons. These intervals were overlooked by the standard basic evaluation and the reservoir potential has been revisited following the latest integrated advanced results. By combining the results of all these advanced wireline answer products, we were able to properly identify and quantify the additional available reserves and therefore change the classification of these reservoirs from poor to excellent with new develo
{"title":"Integration of Advanced Logging Evaluation Techniques Proves Additional Reserves from Thin Bed, Low Resistivity Pay Formations","authors":"Ying Chun Guan, M. Rashaid, L. Hayat, Qasim Dashti, K. Sassi, H. Ayyad, Aisha Embaireeg, Radhika Patro, Sarah Alajmi, Laila Akbar, Abdullah Al Jamaan, Matthew Sullivan","doi":"10.2118/207983-ms","DOIUrl":"https://doi.org/10.2118/207983-ms","url":null,"abstract":"\u0000 The biggest clastic reservoir based in Kuwait has been facing evaluation challenges over the thick intervals of highly laminated thin hydrocarbon layers. Conventional wireline tools have a limitation on resolution when it comes to addressing these thin beds. Therefore, the reserves are usually underestimated, and thin pays are often overlooked. This paper presents the integration of a variety of advanced Wireline tools in order to correctly evaluate and compute reserves from these thin pay zones.\u0000 Acquisition of the triaxial induction tool enabled the study of resistivity anisotropy and the identification of thin pay zones through the distinct reading of the resistivity of the thin sand reservoir. The thin layers have also been further validated using high resolution advanced thin bed analysis from image logs. Advanced spectroscopy and NMR data were used to quantitively define the sand and shale fractions within the thin beds. These measurements were critical to input to improve the resistivity interpretation followed by a reliable estimate of the saturation. High resolution dielectric measurements provided resistivity-independent saturation information enhancing the NMR interpretation using water-filled porosity which was a key input into the identification of the heavy oil presence in Burgan. The newly identified thin pay zones have been further validated using the fluid sampling confirming presence of hydrocarbons with greater understanding of its properties and uniquely quantifying the mobile fluid fractions. The additional available reserves can only be properly determined by combining data from multiple sources to achieve a comprehensive evaluation.\u0000 Resistivity anisotropy was observed based on the separation of vertical and horizontal resistivities and was therefore investigated to understand its root-cause over different zones. By integrating the results from the dielectric dispersion measurements, the diffusion-based NMR data, spectroscopy data, borehole image interpretation and high-resolution sand count delineation of different lithologic units at a finer scale, we were able to identify thin bedded sand-shale intervals in addition to pin-pointing the heavy oil intervals. Hydrocarbon saturations of individual sand layers showed improvement in hydrocarbon volumes, improvement in permeabilities across the studied zones and increased net pay estimations by 12%. Results from the fluid sampling performed across the newly identified thin pays have validated the advanced logging interpretation results and the presence of hydrocarbons. These intervals were overlooked by the standard basic evaluation and the reservoir potential has been revisited following the latest integrated advanced results. By combining the results of all these advanced wireline answer products, we were able to properly identify and quantify the additional available reserves and therefore change the classification of these reservoirs from poor to excellent with new develo","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81120154","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}
With an increasing awareness of minimising the environmental footprint combined with the inclusion of circularity in the oil and gas industry, stricter laws and therefore more rigorous treatment targets will have to be implemented in the waste/resource management. Increasingly complex solid and liquid waste streams result in the further need to implement safer, more advanced technologies. Emission levels, resource recovery, energy efficiency, worker safety, and input material flexibility will become key assessment factors. The vacuum thermal desorption process allows for the recovery of resources from different industrial hazardous wastes. At the core of the process is a specially designed vacuum evaporator chamber utilizing indirect heat and controlled vacuum to evaporate contaminants. With this process, resources can be recovered and solids/mineral fractions decontaminated therefore minimising the hazardous waste and bringing valuable resources back into the value chain. A wide range of input materials, independently from their consistency, can be treated using the same process, as a result of the batch-wise working principle of the vacuum evaporator. The process reduces air emissions derived from two sources. One originates from the thermal oil heating system (flue gas), the other from the vacuum desorption process (exhaust). For the latter, in an oily waste recycling facility that processes approximately 30,000 tonnes per year, <<100 m3/h are emitted, of which on average 96 % are nitrogen. Regarding resource recovery, typical output material parameters include clean solids with a TPH (up to C40) content < 0.5 %, oil in product quality with a recovery rate > 99.5 %, and clean water for moistening of the solids. Highest energy efficiency is achieved because the vacuum reduces the boiling point of the hydrocarbons by more than 100 °C. In addition, the recovered oil can be used as fuel to run the equipment. In conclusion, resources will be recovered and therefore hazardous waste reduced, emissions decreased and highest safety for workers observed. Aside from the above stated advantages of using indirectly heated thermal desorption, this process also offers the possibility to be operated using renewable energy. Therefore, guaranteeing zero emissions supporting the health & safety of our environment and its people.
{"title":"Circular Economy in the Oil and Gas Exploration and Production: Resource Recovery from Drill Cuttings and other Oily Wastes","authors":"A. Castilla, M. Zeuss, Michael Schmidt","doi":"10.2118/208062-ms","DOIUrl":"https://doi.org/10.2118/208062-ms","url":null,"abstract":"\u0000 With an increasing awareness of minimising the environmental footprint combined with the inclusion of circularity in the oil and gas industry, stricter laws and therefore more rigorous treatment targets will have to be implemented in the waste/resource management. Increasingly complex solid and liquid waste streams result in the further need to implement safer, more advanced technologies. Emission levels, resource recovery, energy efficiency, worker safety, and input material flexibility will become key assessment factors. The vacuum thermal desorption process allows for the recovery of resources from different industrial hazardous wastes. At the core of the process is a specially designed vacuum evaporator chamber utilizing indirect heat and controlled vacuum to evaporate contaminants. With this process, resources can be recovered and solids/mineral fractions decontaminated therefore minimising the hazardous waste and bringing valuable resources back into the value chain. A wide range of input materials, independently from their consistency, can be treated using the same process, as a result of the batch-wise working principle of the vacuum evaporator. The process reduces air emissions derived from two sources. One originates from the thermal oil heating system (flue gas), the other from the vacuum desorption process (exhaust). For the latter, in an oily waste recycling facility that processes approximately 30,000 tonnes per year, <<100 m3/h are emitted, of which on average 96 % are nitrogen. Regarding resource recovery, typical output material parameters include clean solids with a TPH (up to C40) content < 0.5 %, oil in product quality with a recovery rate > 99.5 %, and clean water for moistening of the solids. Highest energy efficiency is achieved because the vacuum reduces the boiling point of the hydrocarbons by more than 100 °C. In addition, the recovered oil can be used as fuel to run the equipment. In conclusion, resources will be recovered and therefore hazardous waste reduced, emissions decreased and highest safety for workers observed. Aside from the above stated advantages of using indirectly heated thermal desorption, this process also offers the possibility to be operated using renewable energy. Therefore, guaranteeing zero emissions supporting the health & safety of our environment and its people.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81354952","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. Subaihi, Muhammad Syafruddin, Avnish Kumar Mathur, Jaber Abdulmajeed Abdulla, N. Molero, Rao Shafin Ali Khan, Wafaa Belkadi, A. Elattar, M. Talha
Over the past decade, coiled tubing (CT) has been one of the preferred fluid conveyance techniques in tight carbonate oil producers completed with an uncased horizontal section. In the onshore Middle East, conventional CT stimulation practices have delivered inconsistent results in that work environment. This is mainly due to a mix of reservoir heterogeneity, limited CT reach, lower CT pumping rates, uncontrolled fluid placement, and uncertainty of downhole dynamics during the stimulation operations. An intervention workflow recently validated in onshore Middle East to acidize tight carbonate openhole horizontal water injectors was introduced for the first time in an oil producer. The advanced stimulation methodology relies on CT equipped with fiber optics to visualize original fluid coverage across the openhole interval through distributed temperature sensing (DTS). Real-time downhole telemetry is used to control actuation of CT toolstring components and to understand changing downhole conditions. Based on the prestimulation DTS survey, the open hole is segmented into sections requiring different levels of stimulation, fluid placement techniques, and diversion requirements. The candidate carbonate oil producer featured an average permeability of 1.5 md along 8,003 ft of 6-in. uncased horizontal section. Because of the horizontal drain's extended length and the presence of a minimum restriction of 2.365-in in the 3 1/2-in. production tubing, a newly developed CT slim tractor was essential to overcome reach limitations. In addition, a customized drop-ball high-pressure jetting nozzle was coupled to the extended reach assembly to enable high-energy, pinpoint acidizing in the same run. The instrumented CT was initially run until lockup depth, covering only 53% of the horizontal section. The CT slim tractor was then precisely controlled by leveraging real-time downhole force readings, enabling full reach across the open hole. Prestimulation DTS allowed identification of high- and low-intake zones, which enabled informed adjustments of the acidizing schedule, and in particular the level of jetting required in each section. After its actuation via drop-ball, the high-pressure jetting nozzle was operated using downhole pressure readings to ensure optimum jetting conditions and avoid exceeding the fracturing threshold. Upon completion of the stimulation stage, post-stimulation DTS provided an evaluation of the fluid placement effectiveness. After several weeks of production, the oil rate still exceeded the operator's expectations fivefold. This intervention validates the applicability of the advanced matrix stimulation workflow in tight carbonate oil producers completed across a long openhole horizontal interval. It also confirms the value of real-time downhole telemetry for optimal operation of extended reach toolstrings and the understanding of the downhole dynamics throughout stimulation treatments, the combination of which ultimately delivers br
{"title":"New Perspectives for Acidizing Tight Carbonate Oil Producers Completed Across an Extended Openhole Horizontal Section","authors":"M. Subaihi, Muhammad Syafruddin, Avnish Kumar Mathur, Jaber Abdulmajeed Abdulla, N. Molero, Rao Shafin Ali Khan, Wafaa Belkadi, A. Elattar, M. Talha","doi":"10.2118/207733-ms","DOIUrl":"https://doi.org/10.2118/207733-ms","url":null,"abstract":"\u0000 Over the past decade, coiled tubing (CT) has been one of the preferred fluid conveyance techniques in tight carbonate oil producers completed with an uncased horizontal section. In the onshore Middle East, conventional CT stimulation practices have delivered inconsistent results in that work environment. This is mainly due to a mix of reservoir heterogeneity, limited CT reach, lower CT pumping rates, uncontrolled fluid placement, and uncertainty of downhole dynamics during the stimulation operations.\u0000 An intervention workflow recently validated in onshore Middle East to acidize tight carbonate openhole horizontal water injectors was introduced for the first time in an oil producer. The advanced stimulation methodology relies on CT equipped with fiber optics to visualize original fluid coverage across the openhole interval through distributed temperature sensing (DTS). Real-time downhole telemetry is used to control actuation of CT toolstring components and to understand changing downhole conditions. Based on the prestimulation DTS survey, the open hole is segmented into sections requiring different levels of stimulation, fluid placement techniques, and diversion requirements.\u0000 The candidate carbonate oil producer featured an average permeability of 1.5 md along 8,003 ft of 6-in. uncased horizontal section. Because of the horizontal drain's extended length and the presence of a minimum restriction of 2.365-in in the 3 1/2-in. production tubing, a newly developed CT slim tractor was essential to overcome reach limitations. In addition, a customized drop-ball high-pressure jetting nozzle was coupled to the extended reach assembly to enable high-energy, pinpoint acidizing in the same run. The instrumented CT was initially run until lockup depth, covering only 53% of the horizontal section. The CT slim tractor was then precisely controlled by leveraging real-time downhole force readings, enabling full reach across the open hole. Prestimulation DTS allowed identification of high- and low-intake zones, which enabled informed adjustments of the acidizing schedule, and in particular the level of jetting required in each section. After its actuation via drop-ball, the high-pressure jetting nozzle was operated using downhole pressure readings to ensure optimum jetting conditions and avoid exceeding the fracturing threshold. Upon completion of the stimulation stage, post-stimulation DTS provided an evaluation of the fluid placement effectiveness. After several weeks of production, the oil rate still exceeded the operator's expectations fivefold.\u0000 This intervention validates the applicability of the advanced matrix stimulation workflow in tight carbonate oil producers completed across a long openhole horizontal interval. It also confirms the value of real-time downhole telemetry for optimal operation of extended reach toolstrings and the understanding of the downhole dynamics throughout stimulation treatments, the combination of which ultimately delivers br","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79278710","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}
Mohamed Abdel-Basset, J. Rodriguez, K. Slimani, Mostafa Afifi, M. Jamal, Mariam Al-Shuaib
Integrated solutions are important to formulate plans for mature reservoirs under waterflooding due to related dynamic changes and uncertainties. The reservoir and field management need to be handled as an integrated system, and therefore needing a multidisciplinary approach. This paper demonstrates how the integrated multidisciplinary team has developed several workflows covering water-flooding management, production enhancement and maximizing the economic recovery of reservoirs in the North Kuwait asset. Many integrated workflows were developed for water flooding and production optimization. The main integrated workflows that were implemented are as follows: PVT Properties Tool: is designed to estimate the fluid properties throughout the reservoir taking into consideration areal and vertical variations based on trends, and existing data coverage. Opportunity Maps: is a combination of updated reservoir pressure and fluids properties to provide a fast way to identify areas of opportunity to increase/decrease injection or production based on the development strategy. Waterflooding Patterns/segments Review Workflow and Allowable Tool: This integrated analytical workflow applied on predefined reservoir patterns or segments based on geological distribution and/or hydraulic communication, includes several tools like the analysis of production and injection trends, diagnostic plots to assess good vs bad water, Hall plots, Reservoir Pressure data, tracer data, salinity changes and pump intake pressure trends. Geological analysis (cross-sections, well correlations, sand thickness maps) for each layer are integrated in each pattern/segment review to support reservoir connectivity (or the lack thereof). Instantaneous and cumulative VRR are calculated and compared with the overall exploitation strategy and water injection efficiency. Other sub-workflows were developed to improve and manage waterflooding performance such as water recirculation tool and streamline sector modeling simulation. Structured integrated proactive production and ESP optimization workflows: Production optimization is a continuous iterative process (cycles) to improve production, especially in mature fields. This workflow facilitates the identification of opportunities for production optimization with a pro-active approach focusing on flowing wells and rig-less interventions to tackle production challenges and achieve production targets. The Heterogeneity Index (HI) process is utilized to rapidly demonstrate production gain opportunities. This provides family-type problems that are then represented by type-wells for detailed diagnostics. Continuous application and embedding of such structured integrated workflows as standard best practices, deliver significant value in terms of improving the understanding of reservoir performance in order to inject smart (where and when required) and produce smart (sweet healthy spots). This is done on reservoir, segment, pattern and individual
{"title":"Reservoir to Tank: Fit for Purpose Integrated Workflows for Waterflood Management and Production Enhancement","authors":"Mohamed Abdel-Basset, J. Rodriguez, K. Slimani, Mostafa Afifi, M. Jamal, Mariam Al-Shuaib","doi":"10.2118/207316-ms","DOIUrl":"https://doi.org/10.2118/207316-ms","url":null,"abstract":"\u0000 Integrated solutions are important to formulate plans for mature reservoirs under waterflooding due to related dynamic changes and uncertainties. The reservoir and field management need to be handled as an integrated system, and therefore needing a multidisciplinary approach. This paper demonstrates how the integrated multidisciplinary team has developed several workflows covering water-flooding management, production enhancement and maximizing the economic recovery of reservoirs in the North Kuwait asset.\u0000 Many integrated workflows were developed for water flooding and production optimization. The main integrated workflows that were implemented are as follows:\u0000 PVT Properties Tool: is designed to estimate the fluid properties throughout the reservoir taking into consideration areal and vertical variations based on trends, and existing data coverage.\u0000 Opportunity Maps: is a combination of updated reservoir pressure and fluids properties to provide a fast way to identify areas of opportunity to increase/decrease injection or production based on the development strategy.\u0000 Waterflooding Patterns/segments Review Workflow and Allowable Tool: This integrated analytical workflow applied on predefined reservoir patterns or segments based on geological distribution and/or hydraulic communication, includes several tools like the analysis of production and injection trends, diagnostic plots to assess good vs bad water, Hall plots, Reservoir Pressure data, tracer data, salinity changes and pump intake pressure trends. Geological analysis (cross-sections, well correlations, sand thickness maps) for each layer are integrated in each pattern/segment review to support reservoir connectivity (or the lack thereof). Instantaneous and cumulative VRR are calculated and compared with the overall exploitation strategy and water injection efficiency. Other sub-workflows were developed to improve and manage waterflooding performance such as water recirculation tool and streamline sector modeling simulation.\u0000 Structured integrated proactive production and ESP optimization workflows: Production optimization is a continuous iterative process (cycles) to improve production, especially in mature fields. This workflow facilitates the identification of opportunities for production optimization with a pro-active approach focusing on flowing wells and rig-less interventions to tackle production challenges and achieve production targets. The Heterogeneity Index (HI) process is utilized to rapidly demonstrate production gain opportunities. This provides family-type problems that are then represented by type-wells for detailed diagnostics.\u0000 Continuous application and embedding of such structured integrated workflows as standard best practices, deliver significant value in terms of improving the understanding of reservoir performance in order to inject smart (where and when required) and produce smart (sweet healthy spots). This is done on reservoir, segment, pattern and individual","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79737493","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}
High-speed wired drill pipe and its corresponding communication technology not only can achieve high-speed transmission rate and high-capacity, but also can realize real-time monitoring and dual-way communication in whole section, which can prevent downhole problems effectively. As a series system, the homogeneity and robustness of these wired drill pipes are crucial. This paper focuses on how to overcome the difficulty in manufacturing process of information drill pipe and complete the validation test. In order to guarantee the quality of information drill pipe and satisfy the technological requirements of mass production, we optimize the manufacturing process and put forward reasonable test techniques. The optimizations of manufacturing process include the analysis on constant tension of pressure pipe, quantitative cutting pipe and perforation in pipe nozzle. The testing techniques includes magnetic coupling coil impedance test, high pressure test, communication performance test of both single pipe and series system. The test result can be judged and evaluated by the attenuation value of the signal attenuation test and the signal reflection waveform as well as sealing reliability. With the help of the optimization of the manufacturing process and the application of new tooling, the quality and robustness of information drill pipe is improved obviously. Pass rate in primary assembly is increased from 70% to 92%. After the second assembly, pass rate can be increased to 99.5%. Besides, the work efficiency is greatly improved and the process requirements of mass production are satisfied. The validation test can screen out the drill pipe with poor quality and performance effectively thus to improve the reliability of the whole system. By means of the improvement of manufacturing and the validation test, the comprehensive pass rate of information drill pipes is increased from 84% to 95%. During three field tests in Jilin and Daqing Oilfield, the information drill pipes functioned well and accomplished all the test tasks successfully. High-speed wired drill pipe can improve the downhole data transmission on a large margin. The theorical transmission rate can be up to 100 kbps, 10,000 times as much as the traditional mud impulse telemetry. The manufacturing optimization and test technology can guarantee the performance and realize downhole data highway.
{"title":"High-Speed Wired Drill Pipe and its Corresponding Manufacture & Test Technology Research","authors":"Haochen Han, Yong Zhang, Jia Chen, Qi Sun, Zhimeng Fang, Hexiang Li, Zeng Liu, Guobin Zhang","doi":"10.2118/207435-ms","DOIUrl":"https://doi.org/10.2118/207435-ms","url":null,"abstract":"High-speed wired drill pipe and its corresponding communication technology not only can achieve high-speed transmission rate and high-capacity, but also can realize real-time monitoring and dual-way communication in whole section, which can prevent downhole problems effectively. As a series system, the homogeneity and robustness of these wired drill pipes are crucial. This paper focuses on how to overcome the difficulty in manufacturing process of information drill pipe and complete the validation test.\u0000 In order to guarantee the quality of information drill pipe and satisfy the technological requirements of mass production, we optimize the manufacturing process and put forward reasonable test techniques. The optimizations of manufacturing process include the analysis on constant tension of pressure pipe, quantitative cutting pipe and perforation in pipe nozzle. The testing techniques includes magnetic coupling coil impedance test, high pressure test, communication performance test of both single pipe and series system. The test result can be judged and evaluated by the attenuation value of the signal attenuation test and the signal reflection waveform as well as sealing reliability.\u0000 With the help of the optimization of the manufacturing process and the application of new tooling, the quality and robustness of information drill pipe is improved obviously. Pass rate in primary assembly is increased from 70% to 92%. After the second assembly, pass rate can be increased to 99.5%. Besides, the work efficiency is greatly improved and the process requirements of mass production are satisfied. The validation test can screen out the drill pipe with poor quality and performance effectively thus to improve the reliability of the whole system. By means of the improvement of manufacturing and the validation test, the comprehensive pass rate of information drill pipes is increased from 84% to 95%. During three field tests in Jilin and Daqing Oilfield, the information drill pipes functioned well and accomplished all the test tasks successfully.\u0000 High-speed wired drill pipe can improve the downhole data transmission on a large margin. The theorical transmission rate can be up to 100 kbps, 10,000 times as much as the traditional mud impulse telemetry. The manufacturing optimization and test technology can guarantee the performance and realize downhole data highway.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"81 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84310909","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}
Jongsoo Hwang, M. Sharma, Maria-Magdalena Chiotoroiu, T. Clemens
Horizontal water injection wells have the capacity to inject larger volumes of water and have a smaller surface footprint than vertical wells. We present a new quantitative analysis on horizontal well injectivity, injection scheme (matrix vs. fracturing), and fracture containment. To precisely predict injector performance and delineate safe operating conditions, we simulate particle plugging, thermo-poro-elastic stress changes, thermal convection and conduction and fracture growth/containment in reservoirs with multiple layers. Simulation results show that matrix injection in horizontal wells continues over a longer time than vertical injectors as the particle deposition occurs slowly on the larger surface area of horizontal wellbores. At the same time, heat loss occurs uniformly over a longer wellbore length to cause less thermal stress reduction and delay fracture initiation. As a result, the horizontal well length and the injection rates are critical factors that control fracture initiation and long-term injectivity of horizontal injectors. To predict fracture containment accurately, thermal conduction in the caprock and associated thermal stresses are found to be critical factors. We show that ignoring these factors underestimates fracture height growth. Based on our simulation analysis, we suggest strategies to maintain high injectivity and delay fracture initiation by controlling the injection rate, temperature, and water quality. We also provide several methods to design horizontal water injectors to improve fracture containment considering wellbore orientation relative to the local stress orientations. Well placement in the local maximum horizontal stress direction induces longitudinal fractures with better containment and less fracture turning than transverse fractures. When the well is drilled perpendicular to the maximum horizontal stress direction, the initiation of transverse fractures is delayed compared with the longitudinal case. Flow control devices are recommended to segment the flow rate and the wellbore. This helps to ensure uniform water placement and helps to keep the fractures contained.
{"title":"Horizontal Water Injection Wells: Injectivity and Containment of Injection-Induced Fractures","authors":"Jongsoo Hwang, M. Sharma, Maria-Magdalena Chiotoroiu, T. Clemens","doi":"10.2118/207520-ms","DOIUrl":"https://doi.org/10.2118/207520-ms","url":null,"abstract":"\u0000 Horizontal water injection wells have the capacity to inject larger volumes of water and have a smaller surface footprint than vertical wells. We present a new quantitative analysis on horizontal well injectivity, injection scheme (matrix vs. fracturing), and fracture containment. To precisely predict injector performance and delineate safe operating conditions, we simulate particle plugging, thermo-poro-elastic stress changes, thermal convection and conduction and fracture growth/containment in reservoirs with multiple layers.\u0000 Simulation results show that matrix injection in horizontal wells continues over a longer time than vertical injectors as the particle deposition occurs slowly on the larger surface area of horizontal wellbores. At the same time, heat loss occurs uniformly over a longer wellbore length to cause less thermal stress reduction and delay fracture initiation. As a result, the horizontal well length and the injection rates are critical factors that control fracture initiation and long-term injectivity of horizontal injectors. To predict fracture containment accurately, thermal conduction in the caprock and associated thermal stresses are found to be critical factors. We show that ignoring these factors underestimates fracture height growth.\u0000 Based on our simulation analysis, we suggest strategies to maintain high injectivity and delay fracture initiation by controlling the injection rate, temperature, and water quality. We also provide several methods to design horizontal water injectors to improve fracture containment considering wellbore orientation relative to the local stress orientations. Well placement in the local maximum horizontal stress direction induces longitudinal fractures with better containment and less fracture turning than transverse fractures. When the well is drilled perpendicular to the maximum horizontal stress direction, the initiation of transverse fractures is delayed compared with the longitudinal case. Flow control devices are recommended to segment the flow rate and the wellbore. This helps to ensure uniform water placement and helps to keep the fractures contained.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84615111","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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