Flora Marques, Guilherme Cosme Viganô, J. L. Giuriatto, Matheus de Freitas Bezerra
An integrated workflow was developed to support the waterflood design of an onshore field in Brazil. This giant mature field has more than 2000 drilled wells with a long production history that has been declining. The objective of the study was then to improve the recovery factor for that field, as well as generate an integrated workflow that could be adapted and applied to other similar fields. The workflow comprised four main stages. It started with the gathering and treatment of all relevant input data, such as fluid and rock lab data, well logs, and production historical data, to construct a simulation model fit for streamline simulation. A sensitivity study was then conducted analysing the uncertain parameters that had most impact on the simulation results, followed by an uncertainty analysis. Best candidates from this second phase were then used as base cases for the history match process. Eventually, the waterflood design was analysed and optimized considering three main aspects: water allocation, workovers and well placement. The water allocation was first optimized and a reduction of about a fifth of injected water was achieved while maintaining the level of oil production. This was performed using the Pattern Flood Management algorithm (PFM), available in the streamline simulator. This module performed water re-allocation based on bundle efficiency ranking. Different control criteria and optimization parameters were experimented to reach an optimal result. The potential for workovers and, in particular conversion of producers into injectors, was then evaluated but didn't provide a significant improvement in results. Eventually it was considered an increase in well count, looking into optimized well placement based on sweet spot maps and streamline analysis. These solutions were finally combined in an iterative process to ensure interactive effects were accounted for and all aspects jointly optimized and led to an expected increase in oil production of about 5%. This study generated an integrated workflow bridging a long production history with a full-field simulation model for this large mature field. Also, using streamline simulation for such waterflood design optimization appeared fit for purpose. First, it brought an improved efficiency as the workflow required running several scenarios. Second, it allowed to not only consider traditional tools to improve recovery factor but also solutions making use of the understanding of model connectivity the streamline simulator provides.
{"title":"Integrated Workflow for Optimizing Waterflood Design in Brazil Large Mature Field Using Streamline Simulation","authors":"Flora Marques, Guilherme Cosme Viganô, J. L. Giuriatto, Matheus de Freitas Bezerra","doi":"10.4043/29830-ms","DOIUrl":"https://doi.org/10.4043/29830-ms","url":null,"abstract":"\u0000 An integrated workflow was developed to support the waterflood design of an onshore field in Brazil. This giant mature field has more than 2000 drilled wells with a long production history that has been declining. The objective of the study was then to improve the recovery factor for that field, as well as generate an integrated workflow that could be adapted and applied to other similar fields.\u0000 The workflow comprised four main stages. It started with the gathering and treatment of all relevant input data, such as fluid and rock lab data, well logs, and production historical data, to construct a simulation model fit for streamline simulation. A sensitivity study was then conducted analysing the uncertain parameters that had most impact on the simulation results, followed by an uncertainty analysis. Best candidates from this second phase were then used as base cases for the history match process. Eventually, the waterflood design was analysed and optimized considering three main aspects: water allocation, workovers and well placement.\u0000 The water allocation was first optimized and a reduction of about a fifth of injected water was achieved while maintaining the level of oil production. This was performed using the Pattern Flood Management algorithm (PFM), available in the streamline simulator. This module performed water re-allocation based on bundle efficiency ranking. Different control criteria and optimization parameters were experimented to reach an optimal result. The potential for workovers and, in particular conversion of producers into injectors, was then evaluated but didn't provide a significant improvement in results. Eventually it was considered an increase in well count, looking into optimized well placement based on sweet spot maps and streamline analysis. These solutions were finally combined in an iterative process to ensure interactive effects were accounted for and all aspects jointly optimized and led to an expected increase in oil production of about 5%.\u0000 This study generated an integrated workflow bridging a long production history with a full-field simulation model for this large mature field. Also, using streamline simulation for such waterflood design optimization appeared fit for purpose. First, it brought an improved efficiency as the workflow required running several scenarios. Second, it allowed to not only consider traditional tools to improve recovery factor but also solutions making use of the understanding of model connectivity the streamline simulator provides.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88746608","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}
ULTRA™ is a novel and advanced flow assurance coating technology recently introduced in the Brazilian market for upcoming, and challenging, offshore projects expected in the next years. This coating technology has been used for over 9 years, and has been designed, applied and installed in offshore projects worldwide. Particularly over the last year, this thermal insulation system has been applied for a major project in Brazil. It is a thermal insulation system composed of fusion bonded epoxy and styrenic materials. A base 3-layer coating, followed by one or more insulation layers of solid or foamed styrene, and a high ductility outer shield were engineered to outperform some of existing solutions in terms of hydrostatic pressure, subsea stability, overall insulation thickness and associated installation costs. Application trials have been successfully performed to validate plant capabilities for applying the wide range of styrene-based system solutions, for shallow and deep waters. Test results demonstrated that foam and solid versions have a sweet spot in which the system outperforms similar to the wet insulation solutions existing in the Brazilian market. Its solid and foam systems demonstrated capability of delivering lower U - values (Overall Heat Transfer Coefficient) due to their lower thermal conductivity. The benefit of lower thermal conductivity is reflected in a reduced coating thickness and opportunities for potential savings during the transportation and installation activities. In the coming years, the offshore industry in Brazil will demand wet insulation systems delivering improved thermal performance. Hence, lower U value with lower CAPEX and in deeper water depths. This insulation system is a proven flow assurance coating technology, addressing those challenges and now available in the Brazilian market.
{"title":"ULTRA: Flow Assurance Coating Technology - Product Portfolio for Distinct Operating Scenarios","authors":"N. Cunha","doi":"10.4043/29772-ms","DOIUrl":"https://doi.org/10.4043/29772-ms","url":null,"abstract":"\u0000 ULTRA™ is a novel and advanced flow assurance coating technology recently introduced in the Brazilian market for upcoming, and challenging, offshore projects expected in the next years. This coating technology has been used for over 9 years, and has been designed, applied and installed in offshore projects worldwide. Particularly over the last year, this thermal insulation system has been applied for a major project in Brazil. It is a thermal insulation system composed of fusion bonded epoxy and styrenic materials. A base 3-layer coating, followed by one or more insulation layers of solid or foamed styrene, and a high ductility outer shield were engineered to outperform some of existing solutions in terms of hydrostatic pressure, subsea stability, overall insulation thickness and associated installation costs. Application trials have been successfully performed to validate plant capabilities for applying the wide range of styrene-based system solutions, for shallow and deep waters. Test results demonstrated that foam and solid versions have a sweet spot in which the system outperforms similar to the wet insulation solutions existing in the Brazilian market. Its solid and foam systems demonstrated capability of delivering lower U - values (Overall Heat Transfer Coefficient) due to their lower thermal conductivity. The benefit of lower thermal conductivity is reflected in a reduced coating thickness and opportunities for potential savings during the transportation and installation activities. In the coming years, the offshore industry in Brazil will demand wet insulation systems delivering improved thermal performance. Hence, lower U value with lower CAPEX and in deeper water depths. This insulation system is a proven flow assurance coating technology, addressing those challenges and now available in the Brazilian market.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89262400","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 well, Halini X1, was initially tested at an average rate of 1,750 BOPD, with 26-degree API gravity and produced gas at 1.27 MMscfd. The production history showed that the well head parameters were at continous decline due to natural depletion of reservoir. Based on the observation, a complete nodal analysis of multiphase flow was conducted. The results indicated that the natural flow of well will cease when the reservoir pressure decline below 3,000 psig. Therefore, a suitable artificial lift was selected and designed to improve the vertical lift performance of well, making the production sustainbale even at low reservoir pressures. The high gas content of the reservoir fluid, deep reservoir zone, and adequate bottom hole pressure of Halini X1 favored gas lift to be more viable compared to other ALS methods both technically and economically. The results of the gas lift simulation showed enhancment in production; however by changing the tubing size from 3-1/2 inch to 4-1/2 inch further magnified the performance of gas lift injection in terms of production. Based on design, gas lift equipment was installed through workover and the well was put on gas lift injection. The detailed comparison was drawn between natural flow and the flow on gas lift. The outcomes were found with remarkable increase in the life span of well over natural flowing period and led to higher recovery of production.
{"title":"A Case Study in Production Enhancement Through Installation of Optimum Artificial Lift Technology","authors":"Sharafat Ali, Sandeep Kumar, S. A. Kalwar","doi":"10.4043/29848-ms","DOIUrl":"https://doi.org/10.4043/29848-ms","url":null,"abstract":"\u0000 The well, Halini X1, was initially tested at an average rate of 1,750 BOPD, with 26-degree API gravity and produced gas at 1.27 MMscfd. The production history showed that the well head parameters were at continous decline due to natural depletion of reservoir. Based on the observation, a complete nodal analysis of multiphase flow was conducted. The results indicated that the natural flow of well will cease when the reservoir pressure decline below 3,000 psig. Therefore, a suitable artificial lift was selected and designed to improve the vertical lift performance of well, making the production sustainbale even at low reservoir pressures.\u0000 The high gas content of the reservoir fluid, deep reservoir zone, and adequate bottom hole pressure of Halini X1 favored gas lift to be more viable compared to other ALS methods both technically and economically. The results of the gas lift simulation showed enhancment in production; however by changing the tubing size from 3-1/2 inch to 4-1/2 inch further magnified the performance of gas lift injection in terms of production.\u0000 Based on design, gas lift equipment was installed through workover and the well was put on gas lift injection. The detailed comparison was drawn between natural flow and the flow on gas lift. The outcomes were found with remarkable increase in the life span of well over natural flowing period and led to higher recovery of production.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77837601","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}
Phased Field Development (PFD) is a well-known method to mitigate reservoir uncertainty. However, by its very nature a PFD lowers the Net Present Value (NPV) of the project compared to a Full Field Development (FFD). In this work, multiple scenarios are investigated to increase the attractiveness of PFD vis-a-vis FFD. The most promising concepts are identified and their key financial characteristics are studied with a view to providing a roadmap that can assist in efficient planning of future deepwater field developments. Annual cash flows along with revenue and profit margins are estimated and compared for the two options for a potential deepwater field development in US Gulf of Mexico.
{"title":"Increasing the Attractiveness of Phased Field Development: De-Risk Reservoir Uncertainty with Efficient Field Development Solution","authors":"Shiladitya Basu, Tirtharaj Bhaumik","doi":"10.4043/29784-ms","DOIUrl":"https://doi.org/10.4043/29784-ms","url":null,"abstract":"\u0000 Phased Field Development (PFD) is a well-known method to mitigate reservoir uncertainty. However, by its very nature a PFD lowers the Net Present Value (NPV) of the project compared to a Full Field Development (FFD). In this work, multiple scenarios are investigated to increase the attractiveness of PFD vis-a-vis FFD. The most promising concepts are identified and their key financial characteristics are studied with a view to providing a roadmap that can assist in efficient planning of future deepwater field developments.\u0000 Annual cash flows along with revenue and profit margins are estimated and compared for the two options for a potential deepwater field development in US Gulf of Mexico.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76141693","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}
Jian Zhao, M. J. R. Oliveira, Junfeng Zhao, K. Ren, Leonardo Costa de Oliveira, I. O. Carmo, Cristiano Camelo Rancan, Qicai Deng
Libra carbonate reservoirs, besides its great heterogeneity, are also characterized by occurrence of igneous rocks, as a challenge to reservoir modeling and production performance prediction. The objectives of this paper are three fields:1) To better understand the genetic cause of magma events and its relationship with fault activity;2) To minimize the uncertainties of the outcomes from geophysical and petrophysical methods;3) To enhance the reliability and accuracy of igneous rocks’ prediction. Several semi-quantitative to quantitative assessment methods have been attempted and employed to evaluate the fault activity. The result from fault growth index reveal that the Class-I faults are continuously active from PIC (PiÇarras Fm.) to BVE (Barra Velha Fm.), throughout the whole rift period, but the time when they have the highest activity intensity value is getting later from west to east. In NW structure of Libra, their most intensity appeared during the period of PIC deposition. In Central structure, they show their highest activity values mainly during ITP (Itapema Fm.) stage. And the Class-I faults in SE structure continue to be active even during the deposition time of BVE. The eight class-II faults show their movement mainly during the PIC and ITP period and they were no longer active during BVE stage. The two Class-II faults in NW structure were more active, with a largest value of activity intensity during PIC while the same order faults in Central and SE structure lasted for even longer time, and their highest intensity occurred in ITP deposition period. All the faults, including Class-I faults and Class-II faults, usually have a longer activity duration and a higher intensity in their middle part, and a relatively shorter activity time and a lower intensity value in their two endpoints (Figure.3). An igneous rocks genetic geological model is built up. The Aptian volcano was interpreted as a type of fissure event when the magma was distributed along the regional faults. The Class-II and some Class-I faults and their movement contribute to the formation of Aptian craters and then controlled the distribution of afterward extrusive rock. The Class-I faults and their later reactivation play a key role in the distribution of Santonian intrusive igneous rocks. Under the guidance of such model, methods of multi-scale and multi-disciplinary could be used to predict igneous rocks, which could significantly and effectively reduce the uncertainties of seismic data and enhance the reliability and accuracy of igneous rocks’ prediction.
{"title":"Fault Activity and its Influences on Distribution of Igneous Rocks in Libra Block, Santos Basin: Semi-Quantitative to Quantitative Assessment of Fault Activity Based on High-Resolution 3D Seismic Data","authors":"Jian Zhao, M. J. R. Oliveira, Junfeng Zhao, K. Ren, Leonardo Costa de Oliveira, I. O. Carmo, Cristiano Camelo Rancan, Qicai Deng","doi":"10.4043/29691-ms","DOIUrl":"https://doi.org/10.4043/29691-ms","url":null,"abstract":"\u0000 Libra carbonate reservoirs, besides its great heterogeneity, are also characterized by occurrence of igneous rocks, as a challenge to reservoir modeling and production performance prediction. The objectives of this paper are three fields:1) To better understand the genetic cause of magma events and its relationship with fault activity;2) To minimize the uncertainties of the outcomes from geophysical and petrophysical methods;3) To enhance the reliability and accuracy of igneous rocks’ prediction.\u0000 Several semi-quantitative to quantitative assessment methods have been attempted and employed to evaluate the fault activity. The result from fault growth index reveal that the Class-I faults are continuously active from PIC (PiÇarras Fm.) to BVE (Barra Velha Fm.), throughout the whole rift period, but the time when they have the highest activity intensity value is getting later from west to east. In NW structure of Libra, their most intensity appeared during the period of PIC deposition. In Central structure, they show their highest activity values mainly during ITP (Itapema Fm.) stage. And the Class-I faults in SE structure continue to be active even during the deposition time of BVE. The eight class-II faults show their movement mainly during the PIC and ITP period and they were no longer active during BVE stage. The two Class-II faults in NW structure were more active, with a largest value of activity intensity during PIC while the same order faults in Central and SE structure lasted for even longer time, and their highest intensity occurred in ITP deposition period. All the faults, including Class-I faults and Class-II faults, usually have a longer activity duration and a higher intensity in their middle part, and a relatively shorter activity time and a lower intensity value in their two endpoints (Figure.3).\u0000 An igneous rocks genetic geological model is built up. The Aptian volcano was interpreted as a type of fissure event when the magma was distributed along the regional faults. The Class-II and some Class-I faults and their movement contribute to the formation of Aptian craters and then controlled the distribution of afterward extrusive rock. The Class-I faults and their later reactivation play a key role in the distribution of Santonian intrusive igneous rocks. Under the guidance of such model, methods of multi-scale and multi-disciplinary could be used to predict igneous rocks, which could significantly and effectively reduce the uncertainties of seismic data and enhance the reliability and accuracy of igneous rocks’ prediction.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73492468","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}
Alexandre Rabello, Dorival Natal Neto, E. Coelho, Estevan P. Seraco, Wagner Destro
This article presents a set of analysis and results on Shared-Actuation Control (SAC) techniques, intended for the remote control of valves in subsea manifolds. The discussion covers historical aspects, including presentation of real cases of SAC in Brazilian fields of Petrobras, as well as covers a conceptualization for the technique. The formulated concepts are used indeed to derive a methodology, intended to guide the development of SAC schemes, during engineering projects of subsea manifolds. The discussion is based in part on the unique experience accumulated by Petrobras in the last 20 years, with the development and introduction of a SAC-based subsea manifold in Campos Basin, Brazil, and the latest development efforts ongoing by 2019 for a new generation of SAC, for the application in subsea manifolds to be installed in ultra-deep waters of Pre-Salt fields, in Santos Basin, Brazil. The methodology proposed in this article is based on a comparative approach which aims to incorporate, on design of SAC, the best engineering practices and lessons learned from traditional Electric-Hydraulic Multiplexed Control Systems (EHMCSs). We refer to such approach as the Inheritance & Counterbalance (I&C) Methodology, since it is based on the application of two specific principles, namely, the Inheritance and Counterbalance Principles. The principles are proposed in this article as well. Taking as starting point a set of technical characteristics of EHMCSs, such as employment of redundant subsea electronics and methods of subsea installation, a subsea engineer can apply the I&C Principles to determine if SAC should inherit a given EHMCS characteristic or, if inheritance is not feasible for some reason, adopt alternative requisites on SAC, in order to counterbalance the effects of such no inheritance. The conceptualization of the I&C Methodology allow us effectively applying it, to obtain as result a table of engineering requisites, suitable for SAC schemes destined to subsea manifolds. The proposed table is presented in this article and incorporates several engineering aspects, which are arbitrated from the knowledge on previous applications of Petrobras in subsea control systems. Such applications include both SAC schemes and EHMCSs, featured on fields of Campos and Santos Basins.
{"title":"On the Shared-Actuation Control for the Operation of Manifolds in Subsea Production Systems","authors":"Alexandre Rabello, Dorival Natal Neto, E. Coelho, Estevan P. Seraco, Wagner Destro","doi":"10.4043/29820-ms","DOIUrl":"https://doi.org/10.4043/29820-ms","url":null,"abstract":"\u0000 This article presents a set of analysis and results on Shared-Actuation Control (SAC) techniques, intended for the remote control of valves in subsea manifolds. The discussion covers historical aspects, including presentation of real cases of SAC in Brazilian fields of Petrobras, as well as covers a conceptualization for the technique. The formulated concepts are used indeed to derive a methodology, intended to guide the development of SAC schemes, during engineering projects of subsea manifolds.\u0000 The discussion is based in part on the unique experience accumulated by Petrobras in the last 20 years, with the development and introduction of a SAC-based subsea manifold in Campos Basin, Brazil, and the latest development efforts ongoing by 2019 for a new generation of SAC, for the application in subsea manifolds to be installed in ultra-deep waters of Pre-Salt fields, in Santos Basin, Brazil.\u0000 The methodology proposed in this article is based on a comparative approach which aims to incorporate, on design of SAC, the best engineering practices and lessons learned from traditional Electric-Hydraulic Multiplexed Control Systems (EHMCSs). We refer to such approach as the Inheritance & Counterbalance (I&C) Methodology, since it is based on the application of two specific principles, namely, the Inheritance and Counterbalance Principles. The principles are proposed in this article as well. Taking as starting point a set of technical characteristics of EHMCSs, such as employment of redundant subsea electronics and methods of subsea installation, a subsea engineer can apply the I&C Principles to determine if SAC should inherit a given EHMCS characteristic or, if inheritance is not feasible for some reason, adopt alternative requisites on SAC, in order to counterbalance the effects of such no inheritance.\u0000 The conceptualization of the I&C Methodology allow us effectively applying it, to obtain as result a table of engineering requisites, suitable for SAC schemes destined to subsea manifolds. The proposed table is presented in this article and incorporates several engineering aspects, which are arbitrated from the knowledge on previous applications of Petrobras in subsea control systems. Such applications include both SAC schemes and EHMCSs, featured on fields of Campos and Santos Basins.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78522714","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 production of S1 Greater Sirikit Oil Field production primarily contributes from waterflooding operation, where water is reinjected into reservoir to increase reservoir pressure and sweep movable oil to adjacent production wells. Estimated oil gain from waterflooding is expected to be 34 MMSTB with upside volume of 19 MMSTB. One of the complexities of waterflood operation is water qualities. As High solid particles and oil content presenting in injected water leads to reservoir plugging indicating by an increase in injection pressure and reduction in injection rate. With 53% of total water injection wells show signs of plugging, water quality improvement is one of the major projects initiated by S1 asset to tackle the problem. Inadequate produced water treatment results in excessive solid particle and oil in water content. Eventually, it will effect on waterflooding and EOR performance. To maintain production, it is required to improve quality of water treatment in order to sustain oil gain. The gas flotation is one of promising technology and practically established methods to enhance separation of oil substances and particulates from water when simple gravity separation is not sufficient to reach the desired concentration. In this project, the most challenged of this project are of necessity of Outlet TSS Concentration below < 20 and 80% removal particle size > 5 microns and Oil Outlet concentration below 25 ppm, whilst the TSS and oil inlet are approximate 200 ppm. The conventional flotation technologies consists with two main systems as detailed below. (1) Induced Gas Flotation Technology (IGF), (2) Dissolved Gas Flotation Technology (DGF). The difference between DGF and IGF is the bubbles size generation. Typically, the IGF unit produces bubble sizes ranges more than 100 microns, whilst the DGF unit creates bubble sizes below 100 micron. Engineering team sought for appropriate technologies by reviewing COMPANY's past projects as well as screening the commercial channels. Apart from that, team amalgamated with Chulalongkorn University to gain academic point of view and perform JAR test to confidentially ensure Licensor's Technologies. Several factors shall be controlled and optimized to accomplish the performance guarantee via consideration of Flotation technique (DGF and IGF), Retention Time, Bubble Size, Coagulant & Flocculants Chemical properties, Chemical Compatibilities, Operating Condition Control (Pressure, pH). In addition, the selected vendor executes engineering design and construction to deliver superior water quailities. Starting DGF unit to conduct performance test run, DGF unit captivately devises positive outcome of water treatment and demonstates high accuracy and reliable with corresponded correlation model when feed condition changes.
{"title":"1st Development of Advanced Purification of Produced Water Technology at Greater Sirikit Oil Field by Dissolved Gas Flotation Technique","authors":"Nattapong Lertrojanachusit, Urisa Thunmasarnrit, Ratipat Techasuwanna, Phansak Linjongsubongkoch, Ittiwat Sa-Nguanwong, Parntip Kiravanich, Pongsak Metheethara, Saran Umpuch","doi":"10.4043/29791-ms","DOIUrl":"https://doi.org/10.4043/29791-ms","url":null,"abstract":"\u0000 The production of S1 Greater Sirikit Oil Field production primarily contributes from waterflooding operation, where water is reinjected into reservoir to increase reservoir pressure and sweep movable oil to adjacent production wells. Estimated oil gain from waterflooding is expected to be 34 MMSTB with upside volume of 19 MMSTB. One of the complexities of waterflood operation is water qualities. As High solid particles and oil content presenting in injected water leads to reservoir plugging indicating by an increase in injection pressure and reduction in injection rate. With 53% of total water injection wells show signs of plugging, water quality improvement is one of the major projects initiated by S1 asset to tackle the problem.\u0000 Inadequate produced water treatment results in excessive solid particle and oil in water content. Eventually, it will effect on waterflooding and EOR performance. To maintain production, it is required to improve quality of water treatment in order to sustain oil gain. The gas flotation is one of promising technology and practically established methods to enhance separation of oil substances and particulates from water when simple gravity separation is not sufficient to reach the desired concentration.\u0000 In this project, the most challenged of this project are of necessity of Outlet TSS Concentration below < 20 and 80% removal particle size > 5 microns and Oil Outlet concentration below 25 ppm, whilst the TSS and oil inlet are approximate 200 ppm. The conventional flotation technologies consists with two main systems as detailed below. (1) Induced Gas Flotation Technology (IGF), (2) Dissolved Gas Flotation Technology (DGF). The difference between DGF and IGF is the bubbles size generation. Typically, the IGF unit produces bubble sizes ranges more than 100 microns, whilst the DGF unit creates bubble sizes below 100 micron.\u0000 Engineering team sought for appropriate technologies by reviewing COMPANY's past projects as well as screening the commercial channels. Apart from that, team amalgamated with Chulalongkorn University to gain academic point of view and perform JAR test to confidentially ensure Licensor's Technologies. Several factors shall be controlled and optimized to accomplish the performance guarantee via consideration of Flotation technique (DGF and IGF), Retention Time, Bubble Size, Coagulant & Flocculants Chemical properties, Chemical Compatibilities, Operating Condition Control (Pressure, pH).\u0000 In addition, the selected vendor executes engineering design and construction to deliver superior water quailities. Starting DGF unit to conduct performance test run, DGF unit captivately devises positive outcome of water treatment and demonstates high accuracy and reliable with corresponded correlation model when feed condition changes.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80028834","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}
N. Orellana, A. Gaibor, R. Astudillo, S. Lozada, E. Muñoz, Telmo Tamayo, Luis Roberto Bailón, Carlos Alberto Padilla
The high water cut 98,5% caused the abandonment of a directional well, which was reactivated after 3 years using a water shut off technique. Offset wells production behavior, stratigraphic seal layers distribution, reservoir properties, and cased hole logging data played a relevant role for the well planning, reactivation and production success of heavy oil from the mature Amo field in the Oriente Basin of Ecuador. The Lower U reservoir production screening from neighbor wells and stratigraphical well correlation supported a rigless acquisition plan of pulse neutron logs to diagnose the fluid flow patterns after 5 years of production and 3 years of a well abandonment. Further corrosion and cement log was run to check the well integrity and compared it with initial cement log to discard possible cement channeling suspicion behind casing. Finally, water shut off well program was carried out. The acquired neutron logs showed flushed zone from two former producing perforations as well as remaining hydrocarbons in the upper perforated zone. The gamma ray log activation was detected just below the oil water contact while the oxygen activation log "OAI" was highlighted just above the gamma ray activation at the same depth where CBL log experienced picks perturbations suggesting bad cement an possible channeling behind casing. The OAI ended just in the upper unit perforations where another CBL pick was recorded. These evidences supported possible cross flow hypothesis from the bottom to the top producing zones. The water shut off job squeezed the lower perforation zone and re-perforated the upper unit to reactivate the abandoned well. The cement and corrosion logs suggested a good conditions of casing and zone isolation from aquifer. The well reactivation produced 700 bbl/d of water formation (100% BSW) during a month, the water salinity gradually increased from 16000 ppm to 45000 ppm NaCl. Likewise water cut diminished to 17% and 170 bbl of oil was pumped daily after voiding the cross flowed fluid (44000 bbl). Furthemore, the unknown productivity index for ESP pump design was unveiled. Stratigraphic well correlation indicated the shale layer continuity and thickness variability, which in combination with shale buffers occurrence were controlling the production behavior in offset wells. These aspects led to get updated cased hole logging data to identify opportunities for re-activation of abandoned well unlocking by-passed oil reserves after successful water shut off job execution.
{"title":"Effective Cross Flow Diagnostic by Pulse Neutron, Cement Logs and Fluid Production: Water Shut Off Well Case in Amo Field","authors":"N. Orellana, A. Gaibor, R. Astudillo, S. Lozada, E. Muñoz, Telmo Tamayo, Luis Roberto Bailón, Carlos Alberto Padilla","doi":"10.4043/29741-ms","DOIUrl":"https://doi.org/10.4043/29741-ms","url":null,"abstract":"\u0000 The high water cut 98,5% caused the abandonment of a directional well, which was reactivated after 3 years using a water shut off technique. Offset wells production behavior, stratigraphic seal layers distribution, reservoir properties, and cased hole logging data played a relevant role for the well planning, reactivation and production success of heavy oil from the mature Amo field in the Oriente Basin of Ecuador.\u0000 The Lower U reservoir production screening from neighbor wells and stratigraphical well correlation supported a rigless acquisition plan of pulse neutron logs to diagnose the fluid flow patterns after 5 years of production and 3 years of a well abandonment. Further corrosion and cement log was run to check the well integrity and compared it with initial cement log to discard possible cement channeling suspicion behind casing. Finally, water shut off well program was carried out.\u0000 The acquired neutron logs showed flushed zone from two former producing perforations as well as remaining hydrocarbons in the upper perforated zone. The gamma ray log activation was detected just below the oil water contact while the oxygen activation log \"OAI\" was highlighted just above the gamma ray activation at the same depth where CBL log experienced picks perturbations suggesting bad cement an possible channeling behind casing. The OAI ended just in the upper unit perforations where another CBL pick was recorded. These evidences supported possible cross flow hypothesis from the bottom to the top producing zones. The water shut off job squeezed the lower perforation zone and re-perforated the upper unit to reactivate the abandoned well. The cement and corrosion logs suggested a good conditions of casing and zone isolation from aquifer. The well reactivation produced 700 bbl/d of water formation (100% BSW) during a month, the water salinity gradually increased from 16000 ppm to 45000 ppm NaCl. Likewise water cut diminished to 17% and 170 bbl of oil was pumped daily after voiding the cross flowed fluid (44000 bbl). Furthemore, the unknown productivity index for ESP pump design was unveiled.\u0000 Stratigraphic well correlation indicated the shale layer continuity and thickness variability, which in combination with shale buffers occurrence were controlling the production behavior in offset wells. These aspects led to get updated cased hole logging data to identify opportunities for re-activation of abandoned well unlocking by-passed oil reserves after successful water shut off job execution.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84674549","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}
Alvaro David Torrez Baptista, M. A. Salvador, G. A. D. Silva, E. F. Martins, J. M. D. Almeida, C. R. Miranda
This work, is based on the multiscale coupling between molecular simulations and reservoir simulators, to explore the brine composition for enhanced oil recovery via the low salinity water injection (LSWI) processes. To achieve this goal, molecular simulations were performed, providing physical-chemistry parameters to reservoir simulators and validate the proposed brine compositional model. The key data required within reservoir simulators are related to the chemical reactions, which are occurring due to the LSWI process, such as their free energies, kinetic constants, ionic strengths, chemical activities, and activation energies. To improve the accuracy of this input dataset, the main aqueous phase geochemical reactions were mapped, adsorption energies of hydrocarbons and brine ions on calcite surface were determined and ions-bearing calcium carbonate were evaluated. The calculations were based on the density functional theory (DFT) and classical molecular dynamics (MD) using Quantum-ESPRESSO and LAMMPS codes, respectively. The geochemical reactions that take place at mineral dissolution and ionic release, related to the LWSI process (MgSO4, CaSO4, BaSO4, Na2CO3, and CaCO3), were also determined. The obtained chemical equilibrium showed that the MgSO4 dissolution reaction was favored, while other minerals did not show a similar trend. Adsorption studies of organic the molecules naphthalene and anthracene over different surface sites were performed. The adsorption energies were similar for both molecules, where the most favorable configuration has the rings oriented parallel to the mineral surface. The potential of mean force obtained for brine ion adsorption suggested that there were no barriers for adsorbing Ca2+ and CO32- brine ions on calcite surface. In contrast, the other ions adsorption (Na+ and Cl-) have presented higher estimated activation energies. The energetic difference showed that the SO42- incorporation in calcite is more favorable than Mg2+. The Ba2+ showed unfavorable incorporation energy. The thermodynamic properties (free energies, entropies, and heat capacities) were calculated from the vibrational properties. Obtaining such input data by molecular simulations can significantly reduce uncertainties, by increasing the reservoir simulators predictive power, facilitating the optimization and understanding of the processes involved in the injection of low salinity fluids. From these results, the obtained equilibrium constants, free energies and adsorption energies can be used as input data in further reservoir simulators. In addition, it would allow the validation of the proposed model from the understanding of the physical processes underlying LSWI.
{"title":"Multiscale Coupling between Molecular Simulations and Reservoir Simulator: Geochemical Reactions for Low Salinity Water Injection in Carbonates","authors":"Alvaro David Torrez Baptista, M. A. Salvador, G. A. D. Silva, E. F. Martins, J. M. D. Almeida, C. R. Miranda","doi":"10.4043/29908-ms","DOIUrl":"https://doi.org/10.4043/29908-ms","url":null,"abstract":"\u0000 This work, is based on the multiscale coupling between molecular simulations and reservoir simulators, to explore the brine composition for enhanced oil recovery via the low salinity water injection (LSWI) processes. To achieve this goal, molecular simulations were performed, providing physical-chemistry parameters to reservoir simulators and validate the proposed brine compositional model. The key data required within reservoir simulators are related to the chemical reactions, which are occurring due to the LSWI process, such as their free energies, kinetic constants, ionic strengths, chemical activities, and activation energies. To improve the accuracy of this input dataset, the main aqueous phase geochemical reactions were mapped, adsorption energies of hydrocarbons and brine ions on calcite surface were determined and ions-bearing calcium carbonate were evaluated. The calculations were based on the density functional theory (DFT) and classical molecular dynamics (MD) using Quantum-ESPRESSO and LAMMPS codes, respectively. The geochemical reactions that take place at mineral dissolution and ionic release, related to the LWSI process (MgSO4, CaSO4, BaSO4, Na2CO3, and CaCO3), were also determined. The obtained chemical equilibrium showed that the MgSO4 dissolution reaction was favored, while other minerals did not show a similar trend. Adsorption studies of organic the molecules naphthalene and anthracene over different surface sites were performed. The adsorption energies were similar for both molecules, where the most favorable configuration has the rings oriented parallel to the mineral surface. The potential of mean force obtained for brine ion adsorption suggested that there were no barriers for adsorbing Ca2+ and CO32- brine ions on calcite surface. In contrast, the other ions adsorption (Na+ and Cl-) have presented higher estimated activation energies. The energetic difference showed that the SO42- incorporation in calcite is more favorable than Mg2+. The Ba2+ showed unfavorable incorporation energy. The thermodynamic properties (free energies, entropies, and heat capacities) were calculated from the vibrational properties. Obtaining such input data by molecular simulations can significantly reduce uncertainties, by increasing the reservoir simulators predictive power, facilitating the optimization and understanding of the processes involved in the injection of low salinity fluids. From these results, the obtained equilibrium constants, free energies and adsorption energies can be used as input data in further reservoir simulators. In addition, it would allow the validation of the proposed model from the understanding of the physical processes underlying LSWI.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84741397","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 definition of Reservoir Rock Types (RRT) is a key challenge in the evaluation and characterization of carbonate reservoirs, and this step is critical as the RRT's define the building blocks for constructing 3D models, as RRT definition links to static and dynamic reservoir properties. This paper describes an innovative and synergetic rock typing process linking geology and petrophysical properties, with a customization of the Flow Zone Indicator (FZI) method to identify RRT's and characterize the heterogeneous oil-bearing Pre-salt carbonates of the Santos Basin, Brazil offshore. A data set of 448 MICP from the Pre-Salt carbonates of Barra Velha Formation was used to build the FZI-RRT model. The optimal number of RRTs, five in total, is determined by using an unsupervised neural network with capillary pressure parameters as inputs, permeability, effective porosity and water saturation. The five classes are delineated by FZI values at 10% porosity and key permeability values, chosen for reasons due flow properties at the core and log scale and suitability in EOR treatments. The five RRTs define a unique permeability/porosity equation that can be propagated to the full core dataset and to the log domain. An ID card for each RRT is then created with specific static and dynamic properties (porosity, permeability, water saturation, relative permeability) that can be used for 3D reservoir modeling.
{"title":"Identifying Reservoir Rock Types Using a Modified FZI Technique in the Brazilian Pre-Salt","authors":"Nadege Bize Forest, F. Abbots, V. Baines, A. Boyd","doi":"10.4043/29694-ms","DOIUrl":"https://doi.org/10.4043/29694-ms","url":null,"abstract":"\u0000 The definition of Reservoir Rock Types (RRT) is a key challenge in the evaluation and characterization of carbonate reservoirs, and this step is critical as the RRT's define the building blocks for constructing 3D models, as RRT definition links to static and dynamic reservoir properties. This paper describes an innovative and synergetic rock typing process linking geology and petrophysical properties, with a customization of the Flow Zone Indicator (FZI) method to identify RRT's and characterize the heterogeneous oil-bearing Pre-salt carbonates of the Santos Basin, Brazil offshore.\u0000 A data set of 448 MICP from the Pre-Salt carbonates of Barra Velha Formation was used to build the FZI-RRT model. The optimal number of RRTs, five in total, is determined by using an unsupervised neural network with capillary pressure parameters as inputs, permeability, effective porosity and water saturation. The five classes are delineated by FZI values at 10% porosity and key permeability values, chosen for reasons due flow properties at the core and log scale and suitability in EOR treatments. The five RRTs define a unique permeability/porosity equation that can be propagated to the full core dataset and to the log domain. An ID card for each RRT is then created with specific static and dynamic properties (porosity, permeability, water saturation, relative permeability) that can be used for 3D reservoir modeling.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85101572","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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