Nicola Raimondi Cominesi, A. Guglielmelli, F. Rotelli, Natale Putignano, P. Roscini, M. Pirrone, G. Galli, Fabio Vinci, D. Rametta, S. Raniolo
Zubair is a giant oil field located in the South of Iraq. The production started in 1951 and current oil production is around 450 kbopd achieved through 150 wells completed in two main formations: Mishrif (carbonate) and 3rd Pay (sandstone). The scope of this paper is to show how an integrated methodology based on core analysis, open-hole and cased-hole logs unlocked the underneath potential of a sand layer (L1) with an anomalous resistivity. Multiple wells, indeed, show resistivity curves in the L1 interval with surprising low values with respect to the average of other levels of the same sandstone reservoir. Therefore, fit-for-purpose open-hole (OH) and cased-hole (CH) log acquisitions have been integrated with information from cores and dynamic data (i.e. production logging) in order to better understand the phenomena behind the low resistivity scenario. As a consequence, several perforation extensions have been performed with L1 as the main target, providing an overall improvement of hydrocarbon deliverability without any increase in water production. In details, routine and special core analyses in L1 samples delineate the typical setting of a fine-grained low resistivity pay sandstone, able to host a large quantity of irreducible water. However, such behavior is not always present among L1 cores. Therefore, a methodology aimed at characterizing this sandstone behavior was mandatory. Nuclear magnetic resonance logging, commonly used to identify low resistivity pays, was not a suitable option due to bad-hole problems. Hence, an approach based on a detailed integration of OH resistivity and CH pulsed neutron logging (PNL) is used to recognize and characterize such low resistivity pay. This method mainly relies on the fact that formation water is very conductive and strongly affects the resistivity, while its effects on PNL measurements are not so pronounced. Such intuition is confirmed by multi-rate PLT interpretations that dynamically describe the L1 sandstone with fair productivity index and high reservoir pressure, together with a significant dry production contribution. In conclusion, a clear geological trend of L1 resistivity behavior is revealed and associated to the decreasing cementation of the matrix and its coarsening in the same direction. The integrated OH/CH methodology allows characterizing low resistivity intervals as pay zones. Such achievement represents an important milestone for the perforation strategy of new and existing wells in Zubair. As a natural consequence, the overall field production has been enhanced by widely applying the new technique without any increase in water-cut.
{"title":"When Water Turns to Oil: Low Resistivity Pay Characterization through Integrated Open-Hole/Cased-Hole Log Interpretation","authors":"Nicola Raimondi Cominesi, A. Guglielmelli, F. Rotelli, Natale Putignano, P. Roscini, M. Pirrone, G. Galli, Fabio Vinci, D. Rametta, S. Raniolo","doi":"10.2118/193101-MS","DOIUrl":"https://doi.org/10.2118/193101-MS","url":null,"abstract":"\u0000 Zubair is a giant oil field located in the South of Iraq. The production started in 1951 and current oil production is around 450 kbopd achieved through 150 wells completed in two main formations: Mishrif (carbonate) and 3rd Pay (sandstone). The scope of this paper is to show how an integrated methodology based on core analysis, open-hole and cased-hole logs unlocked the underneath potential of a sand layer (L1) with an anomalous resistivity.\u0000 Multiple wells, indeed, show resistivity curves in the L1 interval with surprising low values with respect to the average of other levels of the same sandstone reservoir. Therefore, fit-for-purpose open-hole (OH) and cased-hole (CH) log acquisitions have been integrated with information from cores and dynamic data (i.e. production logging) in order to better understand the phenomena behind the low resistivity scenario. As a consequence, several perforation extensions have been performed with L1 as the main target, providing an overall improvement of hydrocarbon deliverability without any increase in water production.\u0000 In details, routine and special core analyses in L1 samples delineate the typical setting of a fine-grained low resistivity pay sandstone, able to host a large quantity of irreducible water. However, such behavior is not always present among L1 cores. Therefore, a methodology aimed at characterizing this sandstone behavior was mandatory. Nuclear magnetic resonance logging, commonly used to identify low resistivity pays, was not a suitable option due to bad-hole problems. Hence, an approach based on a detailed integration of OH resistivity and CH pulsed neutron logging (PNL) is used to recognize and characterize such low resistivity pay. This method mainly relies on the fact that formation water is very conductive and strongly affects the resistivity, while its effects on PNL measurements are not so pronounced. Such intuition is confirmed by multi-rate PLT interpretations that dynamically describe the L1 sandstone with fair productivity index and high reservoir pressure, together with a significant dry production contribution. In conclusion, a clear geological trend of L1 resistivity behavior is revealed and associated to the decreasing cementation of the matrix and its coarsening in the same direction.\u0000 The integrated OH/CH methodology allows characterizing low resistivity intervals as pay zones. Such achievement represents an important milestone for the perforation strategy of new and existing wells in Zubair. As a natural consequence, the overall field production has been enhanced by widely applying the new technique without any increase in water-cut.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"334 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77636635","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. Spagnuolo, F. Scalise, G. Leoni, F. Bigoni, F. Contento, P. Diatto, A. Francesconi, A. Cominelli, L. Osculati
In this work, we address the challenge of modelling a complex, carbonate reservoir, where the fractures network, connected throughout a complex fault framework, represents large part of both the storage and the flow capacity of the system. The asset is a giant, onshore field, developed since the 90's by primary depletion through several horizontal wells, targeting anomalous fluid columns. Different culminations are characterized by specific production drive mechanisms. The objective is to integrate an impressive amount of data into a digital model, suitable to understand fluid flow behavior and support decision. The field is challenging in every geological and dynamic feature. The reservoir complexity ranges from the intricate structural framework (several hundreds of reverse faults), to the puzzling fractures network at different scales, to the unclear role of the low-porosity rock matrix, to the heterogeneous distribution - both laterally and vertically - of fluid properties, related to different combinations of hydrocarbon and acid components. The workflow is based on the adoption of Volume Based Modelling (VBM) to account for seismic faults. Then, large-scale fractures are modelled using a blend of stochastic and deterministic Discrete Fracture Networks (DFNs), while background fractures (BGF) are characterized using a Continuous Fracture Modeling (CFM) formulation. A Dual Porosity - Dual Permeability (DPDK) approach is then implemented for reservoir simulation. The model is finally reconciled with the production data by iterating between geology and simulated dynamic response. The whole modeling and simulation workflow, from static to dynamic model definition, is developed relying on company's top-class computational resources. The DPDK formulation, where DFN is the second medium while the first medium consists of BGF and rock matrix, allows us to simulate the main production mechanism: large-scale discontinuities – DFN – are withdrawal first, and then fluid is recharged by smaller scale features. Besides, the history matching phase, together with accurate production and Pressure-Volume-Temperature (PVT) data analysis, sheds light on the extreme heterogeneity of the field. Petrophysical properties, storage and effective apertures of discontinuities are calibrated according to the production history, and integrated into a comprehensive understanding of the reservoir. Eventually, we reveal how a robust history matched model may be used as a powerful tool to understand the impact of all the involved criticalities on the subsurface fluid behavior and movement in a complex fractured carbonate setting. The challenges addressed in this work provide relevant best practices for carbonate reservoir modelling, in particular highlighting the role of the integration between geology and reservoir engineering to minimize subsurface uncertainties. Furthermore, the PVT model developed in this study proposes new migration scenarios to explain the sour ga
{"title":"Driving Reservoir Modelling Beyond the Limits for a Giant Fractured Carbonate Field - Solving the Puzzle","authors":"M. Spagnuolo, F. Scalise, G. Leoni, F. Bigoni, F. Contento, P. Diatto, A. Francesconi, A. Cominelli, L. Osculati","doi":"10.2118/192708-MS","DOIUrl":"https://doi.org/10.2118/192708-MS","url":null,"abstract":"\u0000 In this work, we address the challenge of modelling a complex, carbonate reservoir, where the fractures network, connected throughout a complex fault framework, represents large part of both the storage and the flow capacity of the system. The asset is a giant, onshore field, developed since the 90's by primary depletion through several horizontal wells, targeting anomalous fluid columns. Different culminations are characterized by specific production drive mechanisms. The objective is to integrate an impressive amount of data into a digital model, suitable to understand fluid flow behavior and support decision.\u0000 The field is challenging in every geological and dynamic feature. The reservoir complexity ranges from the intricate structural framework (several hundreds of reverse faults), to the puzzling fractures network at different scales, to the unclear role of the low-porosity rock matrix, to the heterogeneous distribution - both laterally and vertically - of fluid properties, related to different combinations of hydrocarbon and acid components. The workflow is based on the adoption of Volume Based Modelling (VBM) to account for seismic faults. Then, large-scale fractures are modelled using a blend of stochastic and deterministic Discrete Fracture Networks (DFNs), while background fractures (BGF) are characterized using a Continuous Fracture Modeling (CFM) formulation. A Dual Porosity - Dual Permeability (DPDK) approach is then implemented for reservoir simulation. The model is finally reconciled with the production data by iterating between geology and simulated dynamic response. The whole modeling and simulation workflow, from static to dynamic model definition, is developed relying on company's top-class computational resources.\u0000 The DPDK formulation, where DFN is the second medium while the first medium consists of BGF and rock matrix, allows us to simulate the main production mechanism: large-scale discontinuities – DFN – are withdrawal first, and then fluid is recharged by smaller scale features. Besides, the history matching phase, together with accurate production and Pressure-Volume-Temperature (PVT) data analysis, sheds light on the extreme heterogeneity of the field. Petrophysical properties, storage and effective apertures of discontinuities are calibrated according to the production history, and integrated into a comprehensive understanding of the reservoir. Eventually, we reveal how a robust history matched model may be used as a powerful tool to understand the impact of all the involved criticalities on the subsurface fluid behavior and movement in a complex fractured carbonate setting.\u0000 The challenges addressed in this work provide relevant best practices for carbonate reservoir modelling, in particular highlighting the role of the integration between geology and reservoir engineering to minimize subsurface uncertainties. Furthermore, the PVT model developed in this study proposes new migration scenarios to explain the sour ga","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"101 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77337387","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}
Romulo Bermudez Alvarado, Luis Navas, Abdelkerim Doutoum Mahamat Habib, Yousif Al Katheeri, Sebastian F. Krieger, Chris L. Kiess, D. Farley, Khamis Mostafa, Sherif Shaker, Ahmed N. Khallaf, Sachin Rajadhyaksha
This paper describes how the unique centralizer requirements for extended reach drilling (ERD) wells can be attained. By continuously evaluating past casing runs in combination with engineering input, the learning curve led from a standard centralizer to a highly customized solution. The necessary flow path target to enhance the wellbore isolation through cement placement is met by achieving the right centralizer performance and placing. A single-piece high-restoring-force centralizer is the best solution for the high inclination well profile to obtain the required 9 5/8-in. casing stand-off for ERD wells. The original centralizer design experienced challenges such as high doglegs in some of the longest 9 5/8-in. casing strings that have been run in the UAE to date. Customize the centralizers for different well profiles was necessary. They were developed and tested according to the latest API 10D (2001) specifications using precision equipment to ensure reliable test results that enable accurate hook load and stand-off simulation. Initially, a standard off-the-shelf design of a 9 5/8-in. x 12 1/4-in. single-piece centralizer was used in two wells with the following results:Friction factor exceeded the expected values across the interval on occasion.Total Depth (TD) was sucessfully reached by washing down to bottom.Good centralization as per software design was attained (tageting 80%) with moderate to good isolation. Due to the performance, while running in the hole (RIH), concerns arose due to the unexpectedly high friction factor which, could lead to difficulties RIH and reaching TD in future wells. The modified centralizer design has led to the following improvements:Reduction of friction factor to an average of 0.24 due to a significant decrease in the centralizer running force even through reduced hole diameter intervals and the high dogleg severities (DLS)Reaching TD successfully.Stand-off remained around 80%, as demonstrated by outstanding cement bond log results across the critical sections. It is important to consider that this centralizer was designed not to lose any performance after being run through reduced hole diameter intervals. The application of enhanced centralization design (i.e., standoff >80%) ensured good quality of the cement job.
{"title":"Tailored 9 5/8–in. x 12 1/4-in. Single Piece Centralizer with High Restoring Force for Challenging ERD Wells in UAE","authors":"Romulo Bermudez Alvarado, Luis Navas, Abdelkerim Doutoum Mahamat Habib, Yousif Al Katheeri, Sebastian F. Krieger, Chris L. Kiess, D. Farley, Khamis Mostafa, Sherif Shaker, Ahmed N. Khallaf, Sachin Rajadhyaksha","doi":"10.2118/193046-MS","DOIUrl":"https://doi.org/10.2118/193046-MS","url":null,"abstract":"\u0000 This paper describes how the unique centralizer requirements for extended reach drilling (ERD) wells can be attained. By continuously evaluating past casing runs in combination with engineering input, the learning curve led from a standard centralizer to a highly customized solution. The necessary flow path target to enhance the wellbore isolation through cement placement is met by achieving the right centralizer performance and placing.\u0000 A single-piece high-restoring-force centralizer is the best solution for the high inclination well profile to obtain the required 9 5/8-in. casing stand-off for ERD wells.\u0000 The original centralizer design experienced challenges such as high doglegs in some of the longest 9 5/8-in. casing strings that have been run in the UAE to date. Customize the centralizers for different well profiles was necessary. They were developed and tested according to the latest API 10D (2001) specifications using precision equipment to ensure reliable test results that enable accurate hook load and stand-off simulation.\u0000 Initially, a standard off-the-shelf design of a 9 5/8-in. x 12 1/4-in. single-piece centralizer was used in two wells with the following results:Friction factor exceeded the expected values across the interval on occasion.Total Depth (TD) was sucessfully reached by washing down to bottom.Good centralization as per software design was attained (tageting 80%) with moderate to good isolation.\u0000 Due to the performance, while running in the hole (RIH), concerns arose due to the unexpectedly high friction factor which, could lead to difficulties RIH and reaching TD in future wells. The modified centralizer design has led to the following improvements:Reduction of friction factor to an average of 0.24 due to a significant decrease in the centralizer running force even through reduced hole diameter intervals and the high dogleg severities (DLS)Reaching TD successfully.Stand-off remained around 80%, as demonstrated by outstanding cement bond log results across the critical sections.\u0000 It is important to consider that this centralizer was designed not to lose any performance after being run through reduced hole diameter intervals. The application of enhanced centralization design (i.e., standoff >80%) ensured good quality of the cement job.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85345132","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}
Objective of project specific AUT (Automated Ultrasonic Testing using Zonal Discrimination) Procedure validation is to verify that the implementation of pre-qualified AUT system performance for the inspection of project specific Pipeline girth welds without changing any essential parameter of system qualification processes. As per the requirement of DNV-OS-F101, the purpose of the project specific AUT validation is not to perform any new PoD (Probability of detection) analysis. However, to verify the reliability aspects of the system in terms of HSA (height sizing accuracy) to meet the AUT system qualification requirement is to ascertain the project specific AUT procedure adequately capable of detecting and sizing of the smallest critical defects. This is achieved through a detailed validation programme using the project specific welding procedure and pipe material representing actual pipelay scenario.
{"title":"Project Specific AUT Automatic Ultrasonic Testing Validation to Determine Height Sizing Accuracy for Pipeline Girth Weld ECA Acceptance Criteria.","authors":"Dinesh Putsherry, D. Misra","doi":"10.2118/193170-MS","DOIUrl":"https://doi.org/10.2118/193170-MS","url":null,"abstract":"\u0000 Objective of project specific AUT (Automated Ultrasonic Testing using Zonal Discrimination) Procedure validation is to verify that the implementation of pre-qualified AUT system performance for the inspection of project specific Pipeline girth welds without changing any essential parameter of system qualification processes.\u0000 As per the requirement of DNV-OS-F101, the purpose of the project specific AUT validation is not to perform any new PoD (Probability of detection) analysis. However, to verify the reliability aspects of the system in terms of HSA (height sizing accuracy) to meet the AUT system qualification requirement is to ascertain the project specific AUT procedure adequately capable of detecting and sizing of the smallest critical defects. This is achieved through a detailed validation programme using the project specific welding procedure and pipe material representing actual pipelay scenario.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"58 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87500698","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}
E. Sayapov, Ibrahim Al Farei, Masoud Al Salmi, A. Nunez, Abdulaziz Al Shanfari, H. Gheilani, Andy Smith, T. Yakovlev
In recent years, horizontal drilling has become increasingly important to the oil and gas industry to enable efficient access to complex structures and marginal fields and to increase the reservoir contact area. New technologies have emerged during this time to address post-drilling intervention challenges in such wells. However, complexity of operations in horizontal wells is much higher than that of the vertical wells; therefore effectiveness of the selected technique has a major impact on the operational success and economics. In depressed market environment, economical and operational effectiveness becomes even more important especially when it’s down to complicated, challenging projects that require not only large investments but also simultaneous and continuous utilization of multiple resources, technical disciplines and assets. This paper reviews and compares different ways of horizontal multizonal well preparation for hydraulic fracture stimulation using plug & perf technique in challenging downhole conditions - differential pressures over 15,000 psi, presence of depleted zones complicating cleanout and milling operations between the frac stages, depth control issues. In PDO, there are some gas fields sharing similar downhole conditions whereas fracturing operations are complicated by the requirement of CT cleanouts and/or milling in between the stages. A horizontal well development trial has been implemented to evaluate its economic efficiency and prospects. Depending on the success of this trial, this approach can be spread to other fields with similar characteristics. In these trial wells, multistage completion technologies were not available due to either differential pressure limitations, downhole conditions or completion restrictions, therefore conventional plug & perf approach had to be applied. Such approach, in turn, becomes very challenging in horizontal wells crossing several different formations having multiple severely depleted intervals along the wellbore. These challenges include not only cleanout efficiency and precise depth control during zonal isolation and perforation but also conveyance capabilities. Several different techniques have been tried in PDO so as to discover the most efficient and economical way to complete this task: CT with deployed wireline cable, CT with fiber optic cable, DH tractors and conventional CT with GR-CCl tools in memory mode. All of them have their pros and cons and while saving some money in one small thing, a technique may cause major losses in the other and an operator needs to select the optimum approach taking into consideration multiple aspects. All technologies covered in the paper are well known in the oil business; however some of them were tried in an uncommon environment. For example, although not commonly used in horizontal frac applications (except for perforating for the first stage), tractors were used for plug setting and perforating between the stages and that required w
{"title":"Hydraulic Fracturing in Horizontal Depleted Gas Wells - Challenges, Solutions, Lessons Learnt","authors":"E. Sayapov, Ibrahim Al Farei, Masoud Al Salmi, A. Nunez, Abdulaziz Al Shanfari, H. Gheilani, Andy Smith, T. Yakovlev","doi":"10.2118/192789-MS","DOIUrl":"https://doi.org/10.2118/192789-MS","url":null,"abstract":"\u0000 In recent years, horizontal drilling has become increasingly important to the oil and gas industry to enable efficient access to complex structures and marginal fields and to increase the reservoir contact area. New technologies have emerged during this time to address post-drilling intervention challenges in such wells. However, complexity of operations in horizontal wells is much higher than that of the vertical wells; therefore effectiveness of the selected technique has a major impact on the operational success and economics. In depressed market environment, economical and operational effectiveness becomes even more important especially when it’s down to complicated, challenging projects that require not only large investments but also simultaneous and continuous utilization of multiple resources, technical disciplines and assets. This paper reviews and compares different ways of horizontal multizonal well preparation for hydraulic fracture stimulation using plug & perf technique in challenging downhole conditions - differential pressures over 15,000 psi, presence of depleted zones complicating cleanout and milling operations between the frac stages, depth control issues.\u0000 In PDO, there are some gas fields sharing similar downhole conditions whereas fracturing operations are complicated by the requirement of CT cleanouts and/or milling in between the stages. A horizontal well development trial has been implemented to evaluate its economic efficiency and prospects. Depending on the success of this trial, this approach can be spread to other fields with similar characteristics. In these trial wells, multistage completion technologies were not available due to either differential pressure limitations, downhole conditions or completion restrictions, therefore conventional plug & perf approach had to be applied. Such approach, in turn, becomes very challenging in horizontal wells crossing several different formations having multiple severely depleted intervals along the wellbore. These challenges include not only cleanout efficiency and precise depth control during zonal isolation and perforation but also conveyance capabilities.\u0000 Several different techniques have been tried in PDO so as to discover the most efficient and economical way to complete this task: CT with deployed wireline cable, CT with fiber optic cable, DH tractors and conventional CT with GR-CCl tools in memory mode. All of them have their pros and cons and while saving some money in one small thing, a technique may cause major losses in the other and an operator needs to select the optimum approach taking into consideration multiple aspects.\u0000 All technologies covered in the paper are well known in the oil business; however some of them were tried in an uncommon environment. For example, although not commonly used in horizontal frac applications (except for perforating for the first stage), tractors were used for plug setting and perforating between the stages and that required w","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83257181","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}
T. Narwal, Asaad Busaidi, Habib Ghenaimi, B. Oguni, Zahir Abri, Ahmed Benchekor, A. Hadhrami
In south-eastern part of the Sultanate of Oman, PDO is producing from one of Tight Sour Field (with H2S 1-2%) with current reservoir pressures ranging from 40,000 to 60,000kpa for more than 20 yrs. Due to tight nature of reservoir, the wells are hydraulically fracced to produce, but with time the production rates decline and wells start to produce in unstable mode. This unstable production mode leads to huge scaling and corrosion issues which results in tubing failures requiring huge and expensive workover to restore well production. Due to low production rates and expensive workover makes these intervention very less attractive in terms of Net Present Value (NPV) compared to other opportunities. This paper describes the challenges in restoring production from wells with tubing leaks using conventional workover techniques and the advantages of using new approach of using Hydraulic Work Over Unit (HWOU/Snubbing unit) to workover these wells. Using HWOU for workover restoration time from the failure to restoring production has been reduced from ~2-3yrs to almost less than a year along with significant reduction in overall cost (more than 40% per well). This approach has been successfully applied to 2 wells till dates and upcoming workover will be done in similar manner.
{"title":"Faster Restoration of Wells Using HWOU Snubbing Unit","authors":"T. Narwal, Asaad Busaidi, Habib Ghenaimi, B. Oguni, Zahir Abri, Ahmed Benchekor, A. Hadhrami","doi":"10.2118/193302-MS","DOIUrl":"https://doi.org/10.2118/193302-MS","url":null,"abstract":"\u0000 In south-eastern part of the Sultanate of Oman, PDO is producing from one of Tight Sour Field (with H2S 1-2%) with current reservoir pressures ranging from 40,000 to 60,000kpa for more than 20 yrs. Due to tight nature of reservoir, the wells are hydraulically fracced to produce, but with time the production rates decline and wells start to produce in unstable mode. This unstable production mode leads to huge scaling and corrosion issues which results in tubing failures requiring huge and expensive workover to restore well production. Due to low production rates and expensive workover makes these intervention very less attractive in terms of Net Present Value (NPV) compared to other opportunities.\u0000 This paper describes the challenges in restoring production from wells with tubing leaks using conventional workover techniques and the advantages of using new approach of using Hydraulic Work Over Unit (HWOU/Snubbing unit) to workover these wells.\u0000 Using HWOU for workover restoration time from the failure to restoring production has been reduced from ~2-3yrs to almost less than a year along with significant reduction in overall cost (more than 40% per well). This approach has been successfully applied to 2 wells till dates and upcoming workover will be done in similar manner.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84621331","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}
Peng Chen, T. Willingham, A. Sowaidi, D. Stojković, James M. Brown
In the oil industry, oil and gas are usually accompanied with water when they are produced from the subsurface. How to tackle water is one of the major concerns for the field development, especially as fields mature and water production increases. Produced water reinjection (PWRI) has been considered an environmentally friendly way to handle large amounts of waste fluid, though it needs to be carefully designed. In this paper we present a lab study conducted to determine the water specification requirements for reinjecting produced water back into the subject carbonate reservoirs. The objective of this study is to assess the required produced water quality to maintain matrix injection into the targeted reservoirs. The assessment includes (1) evaluation of the inorganic scaling potential of water sources (fluid compatibility), (2) core flood tests to quantify the impact of various oil content concentrations of produced water on reservoir performance, and (3) a solids loading core flood test to evaluate the injectivity impact of different filtration sizes and different suspended solid concentrations in the produced water. While the previously published paper (Chen et al., 2017) already addresses the scaling and oil content assessments, this paper will present the details of the solids loading core flood test. Produced water (PW) collected from the field was utilized in all stages of this study. Analysis of the composition of the suspended solids in the collected produced water revealed a large amount of iron in the PW’s suspended solids, most likely a corrosion product from the long-distance pipeline between the subject field and the current water treatment and separation facilities. Consequently, the collected produced water’s particle size distribution is inadequate to represent the future reinjected produced water which will come from artificial island wells without going through the pipeline. To replicate the anticipated particle size distribution, filtered produced water was mixed with synthetic solid micro particles according to the particle size distribution measured at the well head and the solids loading specification from the skimmer design to mimic the ‘outlet water’ from the skimmer. The skimmer ‘outlet water’ was then filtered to different sizes, starting with 2μm and relaxing the filtration requirements with each step. To replicate oil carryover, 300 ppm of the field’s oil was added to the sequential filtration stages of the skimmer ‘outlet water’ and was flowed through a preserved core plug of the field’s dominant rock type. Coreflood results suggest that for particle concentrations which represent the solids loading coming from the designed skimmer (TSS=33mg/L), a surface/external filter cake may form with no significant particle penetration into the rock matrix when filtration size is larger than 2µm. More specifically, particles smaller than 2µm did not contribute to the permeability decline, and most of the permeability decl
在石油工业中，当石油和天然气从地下开采出来时，通常伴随着水。如何处理水是油田开发的主要问题之一，特别是随着油田成熟和产水量的增加。采出水回注(PWRI)被认为是处理大量废液的一种环保方式，但需要仔细设计。在本文中，我们进行了一项实验室研究，以确定将采出水回注到所研究的碳酸盐岩储层的水规格要求。本研究的目的是评估维持基质注入目标储层所需的采出水质量。评价内容包括:(1)水源无机结垢潜力评价(流体相容性);(2)岩心驱替试验，量化采出水中不同含油量浓度对油藏动态的影响;(3)固载岩心驱替试验，评价不同滤层尺寸和采出水中不同悬浮固体浓度对注入能力的影响。虽然之前发表的论文(Chen et al.， 2017)已经讨论了结垢和含油量评估，但本文将介绍固体加载岩心驱油测试的细节。从油田收集的采出水(PW)在本研究的所有阶段都得到了利用。对采出水中悬浮固体成分的分析显示，PW的悬浮固体中含有大量的铁，很可能是主题领域与当前水处理和分离设施之间的长距离管道的腐蚀产物。因此，收集到的采出水粒度分布不足以代表未来的回注采出水，这些采出水将来自人工岛井，而不经过管道。为了复制预期的粒度分布，根据井口测量的粒度分布和撇油器设计的固体载荷规格，将过滤后的采出水与合成固体微颗粒混合，以模拟撇油器的“出水”。然后将撇油器“出水”过滤到不同的大小，从2μm开始，每一步过滤要求放宽。为了复制油的携带，将300ppm的油田油添加到撇油器“出水”的连续过滤阶段，并流过油田主要岩石类型的保留岩心塞。岩心驱油结果表明，对于代表来自设计的分离器的固体负载的颗粒浓度(TSS=33mg/L)，当过滤尺寸大于2µm时，可能会形成表面/外部滤饼，而没有明显的颗粒渗透到岩石基质中。更具体地说，小于2µm的颗粒对渗透率下降没有贡献，大部分渗透率下降是由5-10µm范围内的颗粒组成的滤饼造成的。大于10µm的颗粒对渗透率下降没有显著影响，很可能是由于它们的浓度低。
{"title":"Solids Loading Assessment for Produced Water Reinjection in a Carbonate Reservoir","authors":"Peng Chen, T. Willingham, A. Sowaidi, D. Stojković, James M. Brown","doi":"10.2118/193047-MS","DOIUrl":"https://doi.org/10.2118/193047-MS","url":null,"abstract":"\u0000 In the oil industry, oil and gas are usually accompanied with water when they are produced from the subsurface. How to tackle water is one of the major concerns for the field development, especially as fields mature and water production increases. Produced water reinjection (PWRI) has been considered an environmentally friendly way to handle large amounts of waste fluid, though it needs to be carefully designed. In this paper we present a lab study conducted to determine the water specification requirements for reinjecting produced water back into the subject carbonate reservoirs.\u0000 The objective of this study is to assess the required produced water quality to maintain matrix injection into the targeted reservoirs. The assessment includes (1) evaluation of the inorganic scaling potential of water sources (fluid compatibility), (2) core flood tests to quantify the impact of various oil content concentrations of produced water on reservoir performance, and (3) a solids loading core flood test to evaluate the injectivity impact of different filtration sizes and different suspended solid concentrations in the produced water. While the previously published paper (Chen et al., 2017) already addresses the scaling and oil content assessments, this paper will present the details of the solids loading core flood test.\u0000 Produced water (PW) collected from the field was utilized in all stages of this study. Analysis of the composition of the suspended solids in the collected produced water revealed a large amount of iron in the PW’s suspended solids, most likely a corrosion product from the long-distance pipeline between the subject field and the current water treatment and separation facilities. Consequently, the collected produced water’s particle size distribution is inadequate to represent the future reinjected produced water which will come from artificial island wells without going through the pipeline. To replicate the anticipated particle size distribution, filtered produced water was mixed with synthetic solid micro particles according to the particle size distribution measured at the well head and the solids loading specification from the skimmer design to mimic the ‘outlet water’ from the skimmer. The skimmer ‘outlet water’ was then filtered to different sizes, starting with 2μm and relaxing the filtration requirements with each step. To replicate oil carryover, 300 ppm of the field’s oil was added to the sequential filtration stages of the skimmer ‘outlet water’ and was flowed through a preserved core plug of the field’s dominant rock type.\u0000 Coreflood results suggest that for particle concentrations which represent the solids loading coming from the designed skimmer (TSS=33mg/L), a surface/external filter cake may form with no significant particle penetration into the rock matrix when filtration size is larger than 2µm. More specifically, particles smaller than 2µm did not contribute to the permeability decline, and most of the permeability decl","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74209049","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}
Standard form of Contract for Engineering, Procurement and Construction (EPC) Projects in Oil and Gas industry has not gained the favor. Most of the NOCs/IOCs (National Oil Companies / International Oil Companies) prefer to use standalone bespoke EPC Contracts often based on in-house expertise that is developed from using the contents of different standard forms of Contract. This requires a lot of care during the drafting and several rounds of lengthy instructive discussions during the tendering. This paper discusses whether the use of Second Edition of FIDIC Form of Silver Book or Yellow Book released in December 2017 is possible as acceptable standard form of Contract for Oil and Gas Industry with the use of Particular condition to address the special requirements of a Project. The EPC Contracts for onshore and offshore oil and gas projects are generally experiences the issues related to deficient scope definition, force majeure, performance related issues, indemnity, insurance provisions, change orders, termination, limitation of liability, no damage for delay etc. Second edition of FIDIC rainbow suite has striven hard to address the above stated issues with balance distribution of the risk. The 2017 FIDIC Form of Contracts provides increased reciprocity between the Parties (i.e. Employer and Contractor) with an emphasis on notices and time bar provisions. Further, use of standard form of contracts such as FIDIC facilitates better understanding of the risks distribution at the outset of contract due to availability of precedence and accepted explanation of ‘terms and conditions of Contract’.
{"title":"Use of FIDIC 2017 as Standard Form of Contract for EPC Projects in Oil and Gas Industry","authors":"Abhishek Kumar Bidua","doi":"10.2118/193243-MS","DOIUrl":"https://doi.org/10.2118/193243-MS","url":null,"abstract":"\u0000 Standard form of Contract for Engineering, Procurement and Construction (EPC) Projects in Oil and Gas industry has not gained the favor. Most of the NOCs/IOCs (National Oil Companies / International Oil Companies) prefer to use standalone bespoke EPC Contracts often based on in-house expertise that is developed from using the contents of different standard forms of Contract. This requires a lot of care during the drafting and several rounds of lengthy instructive discussions during the tendering. This paper discusses whether the use of Second Edition of FIDIC Form of Silver Book or Yellow Book released in December 2017 is possible as acceptable standard form of Contract for Oil and Gas Industry with the use of Particular condition to address the special requirements of a Project.\u0000 The EPC Contracts for onshore and offshore oil and gas projects are generally experiences the issues related to deficient scope definition, force majeure, performance related issues, indemnity, insurance provisions, change orders, termination, limitation of liability, no damage for delay etc. Second edition of FIDIC rainbow suite has striven hard to address the above stated issues with balance distribution of the risk.\u0000 The 2017 FIDIC Form of Contracts provides increased reciprocity between the Parties (i.e. Employer and Contractor) with an emphasis on notices and time bar provisions. Further, use of standard form of contracts such as FIDIC facilitates better understanding of the risks distribution at the outset of contract due to availability of precedence and accepted explanation of ‘terms and conditions of Contract’.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86235312","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}
Shore pull anchor piles, which have been proven to be effective during pipeline installation, are designed using simplified method and basic structural analysis software in accordance with API RP-2GEO. This method simplifies the interaction between soil and pile using a series of non-linear soil springs along the pile shaft. In this paper, this simplified method is validated by using a refined finite element model and software which captures the soil and structural member interaction behaviours more accurately. The actual project site soil data is used in this paper for the validation. It is proven that the simplified method is capable of considering both geotechnical and structural capacities of the anchor pile and yields a design that is slightly conservative. Additionally, the simplified method is cost effective with regard to the analysis time and software cost. Parametric study such as soil stiffness and pile group effect are carried out to evaluate this simplified method and provide a guidance for the future design.
{"title":"Verification of Shore Pull Anchor Pile Designed Using Simplified Method","authors":"Zongrui Chen, J. Tan, Zhiwei Huang, Eng-Bin Ng","doi":"10.2118/193148-MS","DOIUrl":"https://doi.org/10.2118/193148-MS","url":null,"abstract":"\u0000 Shore pull anchor piles, which have been proven to be effective during pipeline installation, are designed using simplified method and basic structural analysis software in accordance with API RP-2GEO. This method simplifies the interaction between soil and pile using a series of non-linear soil springs along the pile shaft. In this paper, this simplified method is validated by using a refined finite element model and software which captures the soil and structural member interaction behaviours more accurately. The actual project site soil data is used in this paper for the validation. It is proven that the simplified method is capable of considering both geotechnical and structural capacities of the anchor pile and yields a design that is slightly conservative. Additionally, the simplified method is cost effective with regard to the analysis time and software cost. Parametric study such as soil stiffness and pile group effect are carried out to evaluate this simplified method and provide a guidance for the future design.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91183384","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. A. Elfeel, T. Tonkin, Shingo Watanabe, Hicham Abbas, F. Bratvedt, G. Goh, V. Gottumukkala, M. Giddins
Traditional reservoir management relies on irregular information gathering operations such as surface sampling and production logging followed by one or several treatment operations. The availability of both diagnosis and the prescribed remedial operations can cause severe delays in the reservoir management cycle, increasing unplanned down-time and impacting cash flow. These effects can be exacerbated in remote and offshore fields where well intervention is time-intensive. A new, innovative, all-electric, flow control valve (FCV) is now a reality for smart completions. This can support any well penetration scenario including multiple zones per lateral in maximum reservoir contact wells and multi-trip completion in extended reach wells. Each zone is equipped with a permanent intelligent flow control valve, allowing real-time reservoir management and providing high-resolution reservoir control. Valve actuation is semi-instantaneous and field data has shown that the frequency of updating such valves is at least 50 times compared to conventional valves, enabling near continuous closed-loop reservoir management. However, such a high frequency optimization demands computational efficiency as it challenges existing optimization applications, particularly when multiple realizations are considered to account for reservoir uncertainty. In this paper, we present a framework to support field-wide implementation of smart FCVs and hence maintaining a fast closed-loop reservoir management. The framework consists of history matching using Ensemble Kalman Filters (EnKF) where smart FCV data is assimilated to condition a suite of representative reservoir models at a relatively high frequency. Thereafter, a reactive optimizer utilizing a non-linear programming method is applied with the objectives of maximizing instantaneous revenue by determining the optimal positions of the downhole valves under user defined rate, pressure drop, drawdown and setting constraints. This optimization offers production control planning suggestions with the intent of immediate to short-term gain in oil production based upon the downhole measurement and the performance of the near wellbore model. At the same time, a proactive optimizer can be used to determine valve-control settings for longer term objectives such as delaying water/gas breakthrough. The objective of this optimization is equalization of the water/gas front arrival times based upon generation of streamlines and time-of-flight (TOF) analysis. Both modes of optimization are performed efficiently such that a single optimization run is sufficient per geological realization. We use the OLYMPUS reference model, a water flooding case, to demonstrate the workflow. The reactive optimization shows an increase of 25% in the net present value through minimizing water production and increasing injection efficiency, while proactive optimization delays water breakthrough time by 2-4 years. The paper showcases the effectiveness of co
{"title":"Employing Smart Flow Control Valves for Fast Closed-Loop Reservoir Management","authors":"M. A. Elfeel, T. Tonkin, Shingo Watanabe, Hicham Abbas, F. Bratvedt, G. Goh, V. Gottumukkala, M. Giddins","doi":"10.2118/192926-MS","DOIUrl":"https://doi.org/10.2118/192926-MS","url":null,"abstract":"\u0000 Traditional reservoir management relies on irregular information gathering operations such as surface sampling and production logging followed by one or several treatment operations. The availability of both diagnosis and the prescribed remedial operations can cause severe delays in the reservoir management cycle, increasing unplanned down-time and impacting cash flow. These effects can be exacerbated in remote and offshore fields where well intervention is time-intensive.\u0000 A new, innovative, all-electric, flow control valve (FCV) is now a reality for smart completions. This can support any well penetration scenario including multiple zones per lateral in maximum reservoir contact wells and multi-trip completion in extended reach wells. Each zone is equipped with a permanent intelligent flow control valve, allowing real-time reservoir management and providing high-resolution reservoir control. Valve actuation is semi-instantaneous and field data has shown that the frequency of updating such valves is at least 50 times compared to conventional valves, enabling near continuous closed-loop reservoir management. However, such a high frequency optimization demands computational efficiency as it challenges existing optimization applications, particularly when multiple realizations are considered to account for reservoir uncertainty.\u0000 In this paper, we present a framework to support field-wide implementation of smart FCVs and hence maintaining a fast closed-loop reservoir management. The framework consists of history matching using Ensemble Kalman Filters (EnKF) where smart FCV data is assimilated to condition a suite of representative reservoir models at a relatively high frequency. Thereafter, a reactive optimizer utilizing a non-linear programming method is applied with the objectives of maximizing instantaneous revenue by determining the optimal positions of the downhole valves under user defined rate, pressure drop, drawdown and setting constraints. This optimization offers production control planning suggestions with the intent of immediate to short-term gain in oil production based upon the downhole measurement and the performance of the near wellbore model. At the same time, a proactive optimizer can be used to determine valve-control settings for longer term objectives such as delaying water/gas breakthrough. The objective of this optimization is equalization of the water/gas front arrival times based upon generation of streamlines and time-of-flight (TOF) analysis. Both modes of optimization are performed efficiently such that a single optimization run is sufficient per geological realization. We use the OLYMPUS reference model, a water flooding case, to demonstrate the workflow. The reactive optimization shows an increase of 25% in the net present value through minimizing water production and increasing injection efficiency, while proactive optimization delays water breakthrough time by 2-4 years. The paper showcases the effectiveness of co","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90527982","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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