The complexity of dynamic modeling for naturally fractured reservoirs has increased in recent years to incorporate more data and physics, as well as to handle advanced completion designs and development scenarios. While these complex models can provide more insight to difficult problems, they come with higher computational costs. Such a limitation prohibits an asset team from working with a large number of well/fracture scenarios that correctly represent geological uncertainty. This study presents a powerful non-intrusive Embedded Discrete Fracture Model (EDFM) method to efficiently handle millions of natural and hydraulic fractures with hundreds of horizontal wells, which has never been modeled in the literature. Specifically, we built a 3D geological model using a black oil reservoir simulator with 100 square miles in the horizontal area and 11 layers of 165 ft thickness. The total number of matrix cells without considering fractures is over 3 million. In total, 400 horizontal wells with well length of 6000 ft were modeled in two target layers. Each layer contains 200 wells. Each well has 112 hydraulic fractures with cluster spacing of 50 ft. The total number of hydraulic fractures is 44,800. In addition, we generated three cases with 10K, 100K and 1 million 3D natural fractures with dip angle from 70 to 90 degrees. For the case with 1 million natural fractures, the total number of cells is over 42 million. Well performance for the field example, with and without natural fractures, was investigated. This work adds significant value to the well and fracture spacing optimization process during field development planning. The non-intrusive EDFM method has been proven to be an efficient fracture modeling tool for simulating million-level complex hydraulic/natural fractures, which significantly improves accuracy and reduces computational time.
{"title":"Efficient Modeling of Unconventional Well Performance with Millions of Natural and Hydraulic Fractures Using Embedded Discrete Fracture Model EDFM","authors":"Wei Yu, Anuj Gupta, R. Vaidya, K. Sepehrnoori","doi":"10.2118/204548-ms","DOIUrl":"https://doi.org/10.2118/204548-ms","url":null,"abstract":"The complexity of dynamic modeling for naturally fractured reservoirs has increased in recent years to incorporate more data and physics, as well as to handle advanced completion designs and development scenarios. While these complex models can provide more insight to difficult problems, they come with higher computational costs. Such a limitation prohibits an asset team from working with a large number of well/fracture scenarios that correctly represent geological uncertainty. This study presents a powerful non-intrusive Embedded Discrete Fracture Model (EDFM) method to efficiently handle millions of natural and hydraulic fractures with hundreds of horizontal wells, which has never been modeled in the literature. Specifically, we built a 3D geological model using a black oil reservoir simulator with 100 square miles in the horizontal area and 11 layers of 165 ft thickness. The total number of matrix cells without considering fractures is over 3 million. In total, 400 horizontal wells with well length of 6000 ft were modeled in two target layers. Each layer contains 200 wells. Each well has 112 hydraulic fractures with cluster spacing of 50 ft. The total number of hydraulic fractures is 44,800. In addition, we generated three cases with 10K, 100K and 1 million 3D natural fractures with dip angle from 70 to 90 degrees. For the case with 1 million natural fractures, the total number of cells is over 42 million. Well performance for the field example, with and without natural fractures, was investigated. This work adds significant value to the well and fracture spacing optimization process during field development planning. The non-intrusive EDFM method has been proven to be an efficient fracture modeling tool for simulating million-level complex hydraulic/natural fractures, which significantly improves accuracy and reduces computational time.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83257728","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. Alramadhan, Y. Cinar, A. Hussain, Nader Y. BuKhamseen
This paper presents a numerical study to examine how the interplay between the matrix imbibition capillary pressure (Pci) and matrix-fracture transfer affects oil recovery from naturally-fractured reservoirs under waterflooding. We use a dual-porosity, dual-permeability (DPDP) finite difference simulator to investigate the impact of uncertainties in Pci on the waterflood recovery behavior and matrix-fracture transfer. A comprehensive assessment of the factors that control the matrix-fracture transfer, namely Pci, gravity forces, shape factor and fracture-matrix permeabilities is presented. We examine how the use of Pci curves in reservoir simulation can affect the recovery assessment. We present two conceptual scenarios to demonstrate the impact of spontaneous and forced imbibition on the flood-front movement, waterflood recovery processes, and ultimate recovery in the DPDP reservoir systems of varying reservoir quality. The results demonstrate that the inclusion of Pci in reservoir simulation delays the breakthrough time due to a higher displacement efficiency. The study reveals that the matrix-fracture transfer is mainly controlled by the fracture surface area, fracture permeability, shape factor, and the uncertainty in Pci. We underline a discrepancy among various shape factors proposed in the literature due to three main factors: (1) the variations in matrix-block geometries considered, (2) how the physics of imbibition forces that control the multiphase fluid transfer is captured, and (3) how the assumption of pseudo steady-state flow is addressed.
{"title":"Coupled Effect of Imbibition Capillary Pressure and Matrix-Fracture Transfer on Oil Recovery from Dual-Permeability Reservoirs","authors":"A. Alramadhan, Y. Cinar, A. Hussain, Nader Y. BuKhamseen","doi":"10.2118/204819-ms","DOIUrl":"https://doi.org/10.2118/204819-ms","url":null,"abstract":"\u0000 This paper presents a numerical study to examine how the interplay between the matrix imbibition capillary pressure (Pci) and matrix-fracture transfer affects oil recovery from naturally-fractured reservoirs under waterflooding. We use a dual-porosity, dual-permeability (DPDP) finite difference simulator to investigate the impact of uncertainties in Pci on the waterflood recovery behavior and matrix-fracture transfer. A comprehensive assessment of the factors that control the matrix-fracture transfer, namely Pci, gravity forces, shape factor and fracture-matrix permeabilities is presented. We examine how the use of Pci curves in reservoir simulation can affect the recovery assessment. We present two conceptual scenarios to demonstrate the impact of spontaneous and forced imbibition on the flood-front movement, waterflood recovery processes, and ultimate recovery in the DPDP reservoir systems of varying reservoir quality.\u0000 The results demonstrate that the inclusion of Pci in reservoir simulation delays the breakthrough time due to a higher displacement efficiency. The study reveals that the matrix-fracture transfer is mainly controlled by the fracture surface area, fracture permeability, shape factor, and the uncertainty in Pci. We underline a discrepancy among various shape factors proposed in the literature due to three main factors: (1) the variations in matrix-block geometries considered, (2) how the physics of imbibition forces that control the multiphase fluid transfer is captured, and (3) how the assumption of pseudo steady-state flow is addressed.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"80 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80064449","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Junin block in Venezuela was known as an ultra heavy oil belt reserved in extra shallow layers (950ft-1,380ft) with unconsolidated formations. A cluster wells platform drilling was required for the Field Development Program (FDP). Optimisation of the well pattern and drilling of shallow 3D cluster horizontal wells for development of ultra heavy oil are presented in this paper. A well pattern of hand-shape dislocation was forwarded to enhance effective recovery of heavy oil in diamond blind area. Optimisation of the casing programs and control of the well trajectories as well as other key performance drilling were designed. A strict anti-collision barrier design and operation steps were worked out to assure the drilling safety. The loss-resistance, anti-collapse, stick-stuck proof, lubrication and reservoir protection were put into considerations for the drilling fluid design. Recovery of heavy oil was enhanced by means of electrical heating system. Drilling challenges such as shallow target zones, big build-up rate, long horizontal sections, great friction drag and torques, and well trajectories control were experienced and settled. Especially the puzzles of well trajectories control in unconsolidated formations, great friction drag and torques of strings in large displacement long horizontal sections for subsequent operations, and the unstable wellbore were tackled. A typical well data revealed that the horizontal displacement vs. TVD ratio was as high as up to 4.5. The setting depth of surface casing and the determination of KOP were critical to the horizontal wells with large displacement in shallow layers. Pressurized combined drilling and casing-running by means of top drive overcame the drag and torque and achieved planned TD and casing setting depth. The use of electrical wireline heating rod increased the temperatures in and close to the wellbore, and compensated the radius heat loss and avoided viscosity increase of heavy oil so that the output was maintained and improved. It was the first time for successful drilling of shallow 3D cluster horizontal wells with ratio of horizontal displacement vs. TVD over 3.5 in heavy oil belt of Venezuela. The innovative palm-shape dislocation of the well pattern design satisfied the demand of reservoir development and contributed to good production gain of heavy oil.
{"title":"Design of a Dislocation Well Pattern and Drilling of Shallow 3D Cluster Horizontal Wells for Development of Ultra Heavy Oil","authors":"Peng Chen, Guobin Yang, Lei Chen, Guobin Zhang, Haochen Han, Chen Chen","doi":"10.2118/204595-ms","DOIUrl":"https://doi.org/10.2118/204595-ms","url":null,"abstract":"\u0000 The Junin block in Venezuela was known as an ultra heavy oil belt reserved in extra shallow layers (950ft-1,380ft) with unconsolidated formations. A cluster wells platform drilling was required for the Field Development Program (FDP). Optimisation of the well pattern and drilling of shallow 3D cluster horizontal wells for development of ultra heavy oil are presented in this paper.\u0000 A well pattern of hand-shape dislocation was forwarded to enhance effective recovery of heavy oil in diamond blind area. Optimisation of the casing programs and control of the well trajectories as well as other key performance drilling were designed. A strict anti-collision barrier design and operation steps were worked out to assure the drilling safety. The loss-resistance, anti-collapse, stick-stuck proof, lubrication and reservoir protection were put into considerations for the drilling fluid design. Recovery of heavy oil was enhanced by means of electrical heating system.\u0000 Drilling challenges such as shallow target zones, big build-up rate, long horizontal sections, great friction drag and torques, and well trajectories control were experienced and settled. Especially the puzzles of well trajectories control in unconsolidated formations, great friction drag and torques of strings in large displacement long horizontal sections for subsequent operations, and the unstable wellbore were tackled. A typical well data revealed that the horizontal displacement vs. TVD ratio was as high as up to 4.5. The setting depth of surface casing and the determination of KOP were critical to the horizontal wells with large displacement in shallow layers. Pressurized combined drilling and casing-running by means of top drive overcame the drag and torque and achieved planned TD and casing setting depth. The use of electrical wireline heating rod increased the temperatures in and close to the wellbore, and compensated the radius heat loss and avoided viscosity increase of heavy oil so that the output was maintained and improved.\u0000 It was the first time for successful drilling of shallow 3D cluster horizontal wells with ratio of horizontal displacement vs. TVD over 3.5 in heavy oil belt of Venezuela. The innovative palm-shape dislocation of the well pattern design satisfied the demand of reservoir development and contributed to good production gain of heavy oil.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83430925","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}
S. Batarseh, D. P. San Roman Alerigi, Abdullah Al Harith, Wisam J. Assiri
This study evaluates physical and chemical changes induced by high thermal gradients on the formation and their impact to the stability. The heat sources that effect the formation’s stability are varied, including drilling (due to drilling bit friction), perforation, electromagnetic heating (laser or microwave), and thermal recovery or stimulation (steam, resistive heating, combustion, microwave, etc.). This study uses an integrated approach to characterize rock heterogeneity and mapping heat propagation from different heat sources. The information obtained from the study is vital to accurately design and enhance well completion and stimulation This is an integrated analysis approach combining different advanced characterization and visualization techniques to map heat propagation in the formation. Advanced statistical analysis is also used to determine the key parameters and build fundamental prediction algorithms. Characterization on the samples was performed before, during, and after the exposure to thermal sources; it comprised thin-section, high speed infrared thermography (IR), differential thermal analysis and thermogravimetric analyzer (DTA/TGA), scanning electron microscope (SEM), X-ray diffraction (XRD), X-ray fluorescence (XRF), uniaxial stress, and autoscan (provide hardness, composition, velocity, and spectral absorption). The results are integrated, and machine learning is used to derive a predictive algorithm of heat propagation and mapping in the formation with reference to the key formation variables and heterogeneity distribution. Rock heterogeneity affects the rate and patterns of heat propagation into the formation. Within the rock sample, minerals, laminations, and cementations lead to a heterogeneous, and sometimes anisotropic, distribution of thermal properties (thermal conductivity, heat capacity, diffusivity, etc.). These properties are also affected by the rock structure (porosity, micro-cracks, and fractures) and saturation distribution. The results showed the impact of heat on the mechanical properties of the rocks are due to clays dehydration, mineral dissociations, and micro cracks. High speed thermal imaging provides a unique visualization of heat propagation in heterogeneous rocks. Statistical analysis identified key parameters and their impact on thermal propagation; the output was used to build a machine learning algorithm to predict heat distributions in core samples and near-wellbore. Characterizing rock properties and understanding how heterogeneity modifies heat propagation in rocks enables the design of optimal completion and stimulation strategies. This paper discusses how advanced characterization and analysis, combined with novel algorithms, can improve this understanding, and unleash innovation and optimization. The data and information gathered are critical to develop numerical models for field-scale applications.
{"title":"Thermal Effect on Formation Stability Due to Heterogeneity","authors":"S. Batarseh, D. P. San Roman Alerigi, Abdullah Al Harith, Wisam J. Assiri","doi":"10.2118/204663-ms","DOIUrl":"https://doi.org/10.2118/204663-ms","url":null,"abstract":"\u0000 This study evaluates physical and chemical changes induced by high thermal gradients on the formation and their impact to the stability. The heat sources that effect the formation’s stability are varied, including drilling (due to drilling bit friction), perforation, electromagnetic heating (laser or microwave), and thermal recovery or stimulation (steam, resistive heating, combustion, microwave, etc.). This study uses an integrated approach to characterize rock heterogeneity and mapping heat propagation from different heat sources. The information obtained from the study is vital to accurately design and enhance well completion and stimulation\u0000 This is an integrated analysis approach combining different advanced characterization and visualization techniques to map heat propagation in the formation. Advanced statistical analysis is also used to determine the key parameters and build fundamental prediction algorithms. Characterization on the samples was performed before, during, and after the exposure to thermal sources; it comprised thin-section, high speed infrared thermography (IR), differential thermal analysis and thermogravimetric analyzer (DTA/TGA), scanning electron microscope (SEM), X-ray diffraction (XRD), X-ray fluorescence (XRF), uniaxial stress, and autoscan (provide hardness, composition, velocity, and spectral absorption). The results are integrated, and machine learning is used to derive a predictive algorithm of heat propagation and mapping in the formation with reference to the key formation variables and heterogeneity distribution.\u0000 Rock heterogeneity affects the rate and patterns of heat propagation into the formation. Within the rock sample, minerals, laminations, and cementations lead to a heterogeneous, and sometimes anisotropic, distribution of thermal properties (thermal conductivity, heat capacity, diffusivity, etc.). These properties are also affected by the rock structure (porosity, micro-cracks, and fractures) and saturation distribution. The results showed the impact of heat on the mechanical properties of the rocks are due to clays dehydration, mineral dissociations, and micro cracks. High speed thermal imaging provides a unique visualization of heat propagation in heterogeneous rocks. Statistical analysis identified key parameters and their impact on thermal propagation; the output was used to build a machine learning algorithm to predict heat distributions in core samples and near-wellbore.\u0000 Characterizing rock properties and understanding how heterogeneity modifies heat propagation in rocks enables the design of optimal completion and stimulation strategies. This paper discusses how advanced characterization and analysis, combined with novel algorithms, can improve this understanding, and unleash innovation and optimization. The data and information gathered are critical to develop numerical models for field-scale applications.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"194 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89755495","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}
S. Aderemi, Husain Ali Al Lawati, Mansura Khalfan Al Rawahy, Hassan Kolivand, Manish Kumar Singh, C. Darous, Francois D. Bouchet
This paper presents an innovative and practical workflow framework implemented in an Oman southern asset. The asset consists of three isolated accumulations or fields or structures that differ in rock and fluid properties. Each structure has multiple stacked members of Gharif and Alkhlata formations. Oil production started in 1986, with more than 60 commingling wells. The accumulations are not only structurally and stratigraphically complicated but also dynamically complex with numerous input uncertainties. It was impossible to assist the history matching process using a modern optimization-based technique due to the structural complexities of the reservoirs and magnitudes of the uncertain parameters. A structured history-matching approach, Stratigraphic Method (SM), was adopted and guided by suitable subsurface physics by adjusting multi-uncertain parameters simultaneously within the uncertainty envelope to mimic the model response. An essential step in this method is the preliminary analysis, which involved integrating various geological and engineering data to understand the reservoir behavior and the physics controlling the reservoir dynamics. The first step in history-matching these models was to adjust the critical water saturation to correct the numerical water production by honoring the capillary-gravity equilibrium and reservoir fluid flow dynamics. The significance of adjusting the critical water saturation before modifying other parameters and the causes of this numerical water production is discussed. Subsequently, the other major uncertain parameters were identified and modified, while a localized adjustment was avoided except in two wells. This local change was guided by a streamlined technique to ensure minimal model modification and retain geological realism. Overall, acceptable model calibration results were achieved. The history-matching framework's novelty is how the numerical water production was controlled above the transition zone and how the reservoir dynamics were understood from the limited data.
{"title":"Full-Field History-Matching of Commingling Stacked Reservoirs: A Case Study of an Oman Southern Asset","authors":"S. Aderemi, Husain Ali Al Lawati, Mansura Khalfan Al Rawahy, Hassan Kolivand, Manish Kumar Singh, C. Darous, Francois D. Bouchet","doi":"10.2118/204575-ms","DOIUrl":"https://doi.org/10.2118/204575-ms","url":null,"abstract":"\u0000 This paper presents an innovative and practical workflow framework implemented in an Oman southern asset. The asset consists of three isolated accumulations or fields or structures that differ in rock and fluid properties. Each structure has multiple stacked members of Gharif and Alkhlata formations. Oil production started in 1986, with more than 60 commingling wells. The accumulations are not only structurally and stratigraphically complicated but also dynamically complex with numerous input uncertainties.\u0000 It was impossible to assist the history matching process using a modern optimization-based technique due to the structural complexities of the reservoirs and magnitudes of the uncertain parameters. A structured history-matching approach, Stratigraphic Method (SM), was adopted and guided by suitable subsurface physics by adjusting multi-uncertain parameters simultaneously within the uncertainty envelope to mimic the model response. An essential step in this method is the preliminary analysis, which involved integrating various geological and engineering data to understand the reservoir behavior and the physics controlling the reservoir dynamics.\u0000 The first step in history-matching these models was to adjust the critical water saturation to correct the numerical water production by honoring the capillary-gravity equilibrium and reservoir fluid flow dynamics. The significance of adjusting the critical water saturation before modifying other parameters and the causes of this numerical water production is discussed. Subsequently, the other major uncertain parameters were identified and modified, while a localized adjustment was avoided except in two wells. This local change was guided by a streamlined technique to ensure minimal model modification and retain geological realism. Overall, acceptable model calibration results were achieved. The history-matching framework's novelty is how the numerical water production was controlled above the transition zone and how the reservoir dynamics were understood from the limited data.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"298 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74172721","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}
J. Almorihil, A. Mouret, I. Hénaut, V. Mirallés, A. AlSofi
Gravity settling represents the main oil-water separation mechanism. Many separation plants rely only on gravity settling with the aid of demulsifiers (direct or reverse breakers) and other chemicals such as water clarifiers if they are required. Yet, other complementary separation methods exist including filtration, flotation, and centrifugation. In terms of results and more specifically with respect to the separated produced-water, the main threshold on its quality is the dispersed oil content. Even with zero discharge and reinjection into hydrocarbon formations, the presence of residual oil in the aqueous phase represents a concern. High oil content results into formation damage and losses in injectivity which necessitates formation stimulations and hence additional operational expenses. In this work, we investigated the effects of different separation techniques on separated water quality. In addition, we studied the impact of enhanced oil recovery (EOR) chemicals on the different separation techniques in terms of efficiency and water quality. Based on the results, we identified potential improvements to the existing separation process. We used synthetic well-characterized emulsions. The emulsions were prepared at the forecast water: oil ratio using dead crude oil and synthetic representative brines with or without the EOR chemicals. To clearly delineate and distinguish the effectiveness of different separation methods, we exacerbated the conditions by preparing very tight emulsions compared with what is observed on site. With that, we investigated three separation techniques: gravity settling, centrifugation, and filtration. First, we used Jar Tests to study gravity settling, then a benchtop centrifuge at two speeds to evaluate centrifugation potential. Finally, for filtration, we tested two options: membrane and deep-bed filtrations. Concerning the water quality, we performed solvent extraction followed by UV analyses to measure the residual oil content as well as light transmission measurements in order to compare the efficiency of different separation methods. The results of analyses suggest that gravity settling was not efficient in removing oil droplets from water. No separation occurred after 20 minutes in every tested condition. However, note that investigated conditions were severe, tighter emulsions are more difficult to separate compared to those currently observed in the actual separation plant. On the other hand, centrifugation significantly improved light transmission through the separated water. Accordingly, we can conclude that the water quality was largely improved by centrifugation even in the presence of EOR chemicals. In terms of filtration, very good water quality was obtained after membrane filtration. However, significant fouling was observed. In the presence of EOR chemicals, filtration lost its effectiveness due to the low interfacial tension with surfactants and water quality became poor. With deep-bed filtration
{"title":"Produced Water Quality: The Effects of Different Separation Methods for Water and Chemical Floods","authors":"J. Almorihil, A. Mouret, I. Hénaut, V. Mirallés, A. AlSofi","doi":"10.2118/204650-ms","DOIUrl":"https://doi.org/10.2118/204650-ms","url":null,"abstract":"\u0000 Gravity settling represents the main oil-water separation mechanism. Many separation plants rely only on gravity settling with the aid of demulsifiers (direct or reverse breakers) and other chemicals such as water clarifiers if they are required. Yet, other complementary separation methods exist including filtration, flotation, and centrifugation. In terms of results and more specifically with respect to the separated produced-water, the main threshold on its quality is the dispersed oil content. Even with zero discharge and reinjection into hydrocarbon formations, the presence of residual oil in the aqueous phase represents a concern. High oil content results into formation damage and losses in injectivity which necessitates formation stimulations and hence additional operational expenses. In this work, we investigated the effects of different separation techniques on separated water quality. In addition, we studied the impact of enhanced oil recovery (EOR) chemicals on the different separation techniques in terms of efficiency and water quality. Based on the results, we identified potential improvements to the existing separation process.\u0000 We used synthetic well-characterized emulsions. The emulsions were prepared at the forecast water: oil ratio using dead crude oil and synthetic representative brines with or without the EOR chemicals. To clearly delineate and distinguish the effectiveness of different separation methods, we exacerbated the conditions by preparing very tight emulsions compared with what is observed on site. With that, we investigated three separation techniques: gravity settling, centrifugation, and filtration. First, we used Jar Tests to study gravity settling, then a benchtop centrifuge at two speeds to evaluate centrifugation potential. Finally, for filtration, we tested two options: membrane and deep-bed filtrations. Concerning the water quality, we performed solvent extraction followed by UV analyses to measure the residual oil content as well as light transmission measurements in order to compare the efficiency of different separation methods.\u0000 The results of analyses suggest that gravity settling was not efficient in removing oil droplets from water. No separation occurred after 20 minutes in every tested condition. However, note that investigated conditions were severe, tighter emulsions are more difficult to separate compared to those currently observed in the actual separation plant. On the other hand, centrifugation significantly improved light transmission through the separated water. Accordingly, we can conclude that the water quality was largely improved by centrifugation even in the presence of EOR chemicals. In terms of filtration, very good water quality was obtained after membrane filtration. However, significant fouling was observed. In the presence of EOR chemicals, filtration lost its effectiveness due to the low interfacial tension with surfactants and water quality became poor. With deep-bed filtration","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77702809","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. Sehsah, Oscar Bautista Sayago, Tom Newman, F. Mounzer
The technology described in this paper has been developed to challenge the shortcomings of the 40+ year old conventional blade stabilizer. The focus of this paper is to compare drilling performance on two lateral well sections against conventional spiral blade stabilizers. The comparison will highlight the noticeable improvement in drilling performance through analysis of relevant drilling parameters. The new design stabilizer, referred to in this paper as Innovative Drillstring Stabilizer (IDS), can be positioned in the drill string as you would typically do with a conventional spiral blade stabilizer or roller reamer. The design, however, is considerably different. The opened profile, placement and contour of the blades are designed to enhance energy transfer and flow along the tool, improving the transportation of cuttings around the tool while minimizing the occurrences of balling up. The orientation and dome shape of the blades is designed to reduce friction and torque, reduce vibration, improve weight transfer and when slide drilling minimizing the occurrence of hanging up and motor stalls. The engineered drillstring stabilizer was deployed in two wells for trial and technology acceptance purpose. An 8" OD innovative drillstring stabilizer was used as part of a steerable motor bottom hole assembly (BHA) in an integrated operations project. An in-depth performance comparison study was conducted by a specialized and independent third party between two identical BHAs. One (BHA-1), however, included conventional spiral blade stabilizers while the other (BHA-2) adopted the innovative drillstring stabilizers. The pioneering design of the IDS in BHA-2 contributed to reducing the overall torque and aiding in better weight transfer and drilling efficiency. It was possible to apply more weight and the energy transfer to the bit, based on mechanical specific energy (MSE) calculations, showed more efficient drilling conditions. As a result, the ROP, both rotating and sliding showed significant improvement with an overall increase of more than 30%. Better stabilization with BHA-2 aided in less vibration and no motor stalls. In addition, while pulling out of hole, lower hook loads were observed due to the enhanced hole cleaning features, improved hole condition and less friction along the string components. When back on surface no indications of balling-up were observed either. Today, drilling related inefficiencies, in the form of low ROP, non-productive time, damages beyond repair or stuck pipe and lost in hole incidents costs the oil and gas industry millions of dollars on an annual basis. The IDS is designed and proved to address such dysfunctions and improve drilling performance and efficiency while simultaneously stimulates a lower MSE drilling environment.
{"title":"Challenging the Status Quo Leads to Enhanced Drilling Performance","authors":"O. Sehsah, Oscar Bautista Sayago, Tom Newman, F. Mounzer","doi":"10.2118/204876-ms","DOIUrl":"https://doi.org/10.2118/204876-ms","url":null,"abstract":"\u0000 The technology described in this paper has been developed to challenge the shortcomings of the 40+ year old conventional blade stabilizer. The focus of this paper is to compare drilling performance on two lateral well sections against conventional spiral blade stabilizers. The comparison will highlight the noticeable improvement in drilling performance through analysis of relevant drilling parameters.\u0000 The new design stabilizer, referred to in this paper as Innovative Drillstring Stabilizer (IDS), can be positioned in the drill string as you would typically do with a conventional spiral blade stabilizer or roller reamer. The design, however, is considerably different. The opened profile, placement and contour of the blades are designed to enhance energy transfer and flow along the tool, improving the transportation of cuttings around the tool while minimizing the occurrences of balling up. The orientation and dome shape of the blades is designed to reduce friction and torque, reduce vibration, improve weight transfer and when slide drilling minimizing the occurrence of hanging up and motor stalls. The engineered drillstring stabilizer was deployed in two wells for trial and technology acceptance purpose. An 8\" OD innovative drillstring stabilizer was used as part of a steerable motor bottom hole assembly (BHA) in an integrated operations project. An in-depth performance comparison study was conducted by a specialized and independent third party between two identical BHAs. One (BHA-1), however, included conventional spiral blade stabilizers while the other (BHA-2) adopted the innovative drillstring stabilizers.\u0000 The pioneering design of the IDS in BHA-2 contributed to reducing the overall torque and aiding in better weight transfer and drilling efficiency. It was possible to apply more weight and the energy transfer to the bit, based on mechanical specific energy (MSE) calculations, showed more efficient drilling conditions. As a result, the ROP, both rotating and sliding showed significant improvement with an overall increase of more than 30%. Better stabilization with BHA-2 aided in less vibration and no motor stalls. In addition, while pulling out of hole, lower hook loads were observed due to the enhanced hole cleaning features, improved hole condition and less friction along the string components. When back on surface no indications of balling-up were observed either.\u0000 Today, drilling related inefficiencies, in the form of low ROP, non-productive time, damages beyond repair or stuck pipe and lost in hole incidents costs the oil and gas industry millions of dollars on an annual basis. The IDS is designed and proved to address such dysfunctions and improve drilling performance and efficiency while simultaneously stimulates a lower MSE drilling environment.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77862904","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}
Klemens Katterbauer, A. Marsala, Abdulaziz Al Qasim, A. Yousif
Sustainability and reducing carbon footprint has attracted attention in the oil and gas industry to optimize recovery and increase efficiency. The 4th Industrial Revolution has made an enormous impact in the oil and gas industry and on analyzing carbon footprint reduction opportunities. This allows classification of various reservoir operations, installation of permanent sensors and robots on the field, and reduction of overall power consumption. We present an overview of new AI approaches for optimizing reservoir performance while reducing their carbon footprint. We will outline the significant carbon emissions contributors for field operations and how their impact will change throughout the production's lifecycle from a reservoir. Based on this analysis, we will outline via an AI-driven optimization framework areas of improvement to reduce the carbon footprint considering the uncertainty. We analyzed the framework's performance on a synthetic reservoir model with several producing wells, water, and CO2 injecting wells. Beneficial in reducing carbon emissions from the field is the reuse and injection of CO2 for enhancing hydrocarbon production from the reservoir. One hundred different scenarios were then investigated utilizing an innovative autoregressive network model to determine the impact of these components on the overall carbon emission of the field and determine its uncertainty. The conclusions from the analysis were then incorporated into a data-driven optimization routine to minimize carbon footprint while maximizing reservoir performance. The final optimization results of the showcase outlined the ability to reduce the carbon footprint significantly.
{"title":"Minimizing Carbon Footprint by Smart Sustainable Reservoir Management","authors":"Klemens Katterbauer, A. Marsala, Abdulaziz Al Qasim, A. Yousif","doi":"10.2118/204752-ms","DOIUrl":"https://doi.org/10.2118/204752-ms","url":null,"abstract":"\u0000 Sustainability and reducing carbon footprint has attracted attention in the oil and gas industry to optimize recovery and increase efficiency. The 4th Industrial Revolution has made an enormous impact in the oil and gas industry and on analyzing carbon footprint reduction opportunities. This allows classification of various reservoir operations, installation of permanent sensors and robots on the field, and reduction of overall power consumption.\u0000 We present an overview of new AI approaches for optimizing reservoir performance while reducing their carbon footprint. We will outline the significant carbon emissions contributors for field operations and how their impact will change throughout the production's lifecycle from a reservoir. Based on this analysis, we will outline via an AI-driven optimization framework areas of improvement to reduce the carbon footprint considering the uncertainty.\u0000 We analyzed the framework's performance on a synthetic reservoir model with several producing wells, water, and CO2 injecting wells. Beneficial in reducing carbon emissions from the field is the reuse and injection of CO2 for enhancing hydrocarbon production from the reservoir. One hundred different scenarios were then investigated utilizing an innovative autoregressive network model to determine the impact of these components on the overall carbon emission of the field and determine its uncertainty. The conclusions from the analysis were then incorporated into a data-driven optimization routine to minimize carbon footprint while maximizing reservoir performance. The final optimization results of the showcase outlined the ability to reduce the carbon footprint significantly.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82842083","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}
Zhixiong Xu, Xue-qing Teng, Ning Li, Hongtao Liu, Caiting Zhao, Bo Zhou, Bo Zou, Wei Yu
The implementation of drilling technique for multiple lithology interbeds and high-pressure anhydrite-salt in the complex Mountain Front area has been completed. The plastic creep of the anhydrite-salt layers, the losses of the low-pressure sandstone, the overflow of the high-pressure salt-water, the narrow mud density window and frequent pipe-stuck occurrence are significant issues, which trigger significant engineering challenges downhole. This study presents the application of the reaming-while-drilling (RWD) technology which has led to minimize the downhole non-productive time (NPT) and achieve successful results. The RWD technique was applied in the composite anhydrite-salt formation of the Kumugeliemu group. Through optimized combination of the RWD tools, bits, reaming blades, and the mechanical analysis the drill string with shock-absorbing design and hydraulics optimization to guarantee the bit and the reamer blades have the proper pressure drop, hydraulic horsepower and flow-field distribution, the RWD was used with the vertical seeking tool drilling technology, resulting in minimum vibration and/or stick-slip, and achieving the expected rate of penetration (ROP) as well as target inclination. It improved the operation efficiency significantly while avoiding the downhole complexities at the same time. Since the geological structure of the offset well Keshen X (no RWD) is similar to Keshen XX (RWD technology was applied), a comparison between the two wells was performed. The reaming meterage in the composite anhydrite-salt layers in Keshen XX was 791 m, spending 15 days, average ROP is 3.73 m/hr. There was no overflew or loss during the drilling. It was smooth, no pipe sticking when checking the reaming effect during the wiper trip and the tripping out. On the other hand, Keshen X spent 29 days with average ROP of 1.35 m/hr to drill the 449 m composite anhydrite-salt rock. Moreover, it was difficult to trip in and trip out during the drilling, and the pipe sticking happened frequently, back-reaming frequently as well. There were losses during both the drilling and the casing running. Due to the unsmooth wellbore, this well increased additional 3 runs of reaming after drilling operation and 4 clean-out runs. 13 days later after the reaming operation, the anhydrite-salt rock creep was checked and found that the hole was still smooth, no pipe sticking existing. Hence, RWD technology has accomplished both goals of preventing the downhole complexities and speeding up drilling. The novel RWD technology can be well illustrated by presenting all the details of its application in salt-base formations.
{"title":"Field Application of Reaming-While-Drilling Technology in the Super Deep Composite Anhydrite-Salt Layers of Kuche Mountain Front in Tarim Oilfield","authors":"Zhixiong Xu, Xue-qing Teng, Ning Li, Hongtao Liu, Caiting Zhao, Bo Zhou, Bo Zou, Wei Yu","doi":"10.2118/204599-ms","DOIUrl":"https://doi.org/10.2118/204599-ms","url":null,"abstract":"\u0000 The implementation of drilling technique for multiple lithology interbeds and high-pressure anhydrite-salt in the complex Mountain Front area has been completed. The plastic creep of the anhydrite-salt layers, the losses of the low-pressure sandstone, the overflow of the high-pressure salt-water, the narrow mud density window and frequent pipe-stuck occurrence are significant issues, which trigger significant engineering challenges downhole. This study presents the application of the reaming-while-drilling (RWD) technology which has led to minimize the downhole non-productive time (NPT) and achieve successful results. The RWD technique was applied in the composite anhydrite-salt formation of the Kumugeliemu group. Through optimized combination of the RWD tools, bits, reaming blades, and the mechanical analysis the drill string with shock-absorbing design and hydraulics optimization to guarantee the bit and the reamer blades have the proper pressure drop, hydraulic horsepower and flow-field distribution, the RWD was used with the vertical seeking tool drilling technology, resulting in minimum vibration and/or stick-slip, and achieving the expected rate of penetration (ROP) as well as target inclination. It improved the operation efficiency significantly while avoiding the downhole complexities at the same time. Since the geological structure of the offset well Keshen X (no RWD) is similar to Keshen XX (RWD technology was applied), a comparison between the two wells was performed. The reaming meterage in the composite anhydrite-salt layers in Keshen XX was 791 m, spending 15 days, average ROP is 3.73 m/hr. There was no overflew or loss during the drilling. It was smooth, no pipe sticking when checking the reaming effect during the wiper trip and the tripping out. On the other hand, Keshen X spent 29 days with average ROP of 1.35 m/hr to drill the 449 m composite anhydrite-salt rock. Moreover, it was difficult to trip in and trip out during the drilling, and the pipe sticking happened frequently, back-reaming frequently as well. There were losses during both the drilling and the casing running. Due to the unsmooth wellbore, this well increased additional 3 runs of reaming after drilling operation and 4 clean-out runs. 13 days later after the reaming operation, the anhydrite-salt rock creep was checked and found that the hole was still smooth, no pipe sticking existing. Hence, RWD technology has accomplished both goals of preventing the downhole complexities and speeding up drilling. The novel RWD technology can be well illustrated by presenting all the details of its application in salt-base formations.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87452034","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}
Current critical flow rate models fail to accurately predict the liquid loading statuses of shale gas horizontal wells. Therefore, a new critical flow rate model for the whole wellbore of shale gas horizontal wells is established. The results of the new model are compared to those of current models through the field case analysis. The new model is based on the dynamic analysis and energy analysis of the deformed liquid-droplet, which takes into account the liquid flow rate, the liquid-droplet deformation and the energy loss caused by the change of buildup rate. The major axis of the maximum stable deformed liquid-droplet is determined based on the energy balance relation. Meanwhile, the suitable drag coefficient equation and surface tension equation applied to shale gas horizontal wells are chosen. Finally, the critical flow rate equation is established and the maximum critical flow rate of the whole wellbore is chosen as the criterion for liquid loading prediction. The precision of liquid loading prediction of the new model is compared to those of the four current models, including Belfroid's model, modified Li's model, liquid film model and modified Wang's model. Field parameters of 29 shale gas horizontal wells are used for the comparison, including parameters of 18 unloaded wells, 2 near loaded-up wells and 9 loaded-up wells. Field case analysis shows that the total precision of liquid loading prediction of the new model is 93.1%, which is higher compared to those of the current four models. The new model can accurately predict the liquid loading statuses of loaded-up wells and near loaded-up wells, while the prediction precision for unloaded wells is high enough for the field application, which is 88.9%. The new model can be used to effectively estimate the field liquid loading statuses of shale gas horizontal wells and choose drainage gas recovery technologies, which considers both the complex wellbore structure and the variation of flowback liquid flow rate in shale gas horizontal wells. The results of the new model fill the gap in existing studies and have a guiding significance for liquid loading prediction in shale gas horizontal wells.
{"title":"A New Model for Predicting Liquid Loading in Shale Gas Horizontal Wells","authors":"Chao Zhou, Zuqing He, Yashu Chen, Zhifa Wang, A. Mulunjkar, Weishu Zhao","doi":"10.2118/204786-ms","DOIUrl":"https://doi.org/10.2118/204786-ms","url":null,"abstract":"\u0000 Current critical flow rate models fail to accurately predict the liquid loading statuses of shale gas horizontal wells. Therefore, a new critical flow rate model for the whole wellbore of shale gas horizontal wells is established. The results of the new model are compared to those of current models through the field case analysis. The new model is based on the dynamic analysis and energy analysis of the deformed liquid-droplet, which takes into account the liquid flow rate, the liquid-droplet deformation and the energy loss caused by the change of buildup rate. The major axis of the maximum stable deformed liquid-droplet is determined based on the energy balance relation. Meanwhile, the suitable drag coefficient equation and surface tension equation applied to shale gas horizontal wells are chosen. Finally, the critical flow rate equation is established and the maximum critical flow rate of the whole wellbore is chosen as the criterion for liquid loading prediction. The precision of liquid loading prediction of the new model is compared to those of the four current models, including Belfroid's model, modified Li's model, liquid film model and modified Wang's model. Field parameters of 29 shale gas horizontal wells are used for the comparison, including parameters of 18 unloaded wells, 2 near loaded-up wells and 9 loaded-up wells. Field case analysis shows that the total precision of liquid loading prediction of the new model is 93.1%, which is higher compared to those of the current four models. The new model can accurately predict the liquid loading statuses of loaded-up wells and near loaded-up wells, while the prediction precision for unloaded wells is high enough for the field application, which is 88.9%. The new model can be used to effectively estimate the field liquid loading statuses of shale gas horizontal wells and choose drainage gas recovery technologies, which considers both the complex wellbore structure and the variation of flowback liquid flow rate in shale gas horizontal wells. The results of the new model fill the gap in existing studies and have a guiding significance for liquid loading prediction in shale gas horizontal wells.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"74 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91484185","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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