we propose a methodology based on document embedding techniques for applying Technology Intelligence Analysis in Oil and Gas (O&G) domain. We build a specialized corpus in O&G domain and train a Vector Space Model (VSM) to represent each document as a vector, in such a way that the distance between two vectors captures their semantic similarity. We explore different analysis on this VSM to infer relations between documents, in order to obtain new insights in a strategic context. this proposed methodology is based on Natural Language Processing (NLP) techniques to obtain strategic insights in a technology intelligence analysis scenario. It consists on generating a vector space model (VSM) induced from a domain-specific Oil and Gas corpus, composed of thousands of scientific articles collected from the Elsevier online database. We explore an approach to represent different entities - such as articles, authors and keywords - in the same vector space, making it possible to correlate them and infer relations of similarity based on their cosine distance. An evaluation metric is also provided in order to assist the training process and hyperparameters optimization. Oil and Gas highly technical vocabulary represents a challenge to NLP applications, in which some terms may assume a completely different meaning from the general - context domain. In this scenario, gathering an Oil and Gas corpus and training specialized vector space models for this specific domain allows increasing the quality in Technology Intelligence Analysis. The most significant finding is that we were able to explicit the semantic relationships between different entities of interest in the same VSM, also linking these relationships together with some additional metadata. An interesting application is to compare the publications of authors affiliated to two or more O&G companies at a given time. These non-trivial correlations are important to gain strategic insights considering a Technology Intelligence Analysis scenario. the novelty of this proposed methodology is the possibility of exploring new insights when correlating different entities in a technology intelligence scenario for the Oil and Gas domain, using a simple yet efficient approach based on document embedding techniques. This method applies some advanced NLP techniques to quickly process more than a hundred thousand documents in a few seconds, without requiring complex hardware resources, which would be impractical using traditional techniques.
{"title":"Technology Intelligence Analysis Based on Document Embedding Techniques for Oil and Gas Domain","authors":"Fábio Corrêa Cordeiro, Diogo da Silva Magalhães Gomes, Flávio Antônio Machado Gomes, Renata Cristina Texeira","doi":"10.4043/29707-ms","DOIUrl":"https://doi.org/10.4043/29707-ms","url":null,"abstract":"\u0000 \u0000 \u0000 we propose a methodology based on document embedding techniques for applying Technology Intelligence Analysis in Oil and Gas (O&G) domain. We build a specialized corpus in O&G domain and train a Vector Space Model (VSM) to represent each document as a vector, in such a way that the distance between two vectors captures their semantic similarity. We explore different analysis on this VSM to infer relations between documents, in order to obtain new insights in a strategic context.\u0000 \u0000 \u0000 \u0000 this proposed methodology is based on Natural Language Processing (NLP) techniques to obtain strategic insights in a technology intelligence analysis scenario. It consists on generating a vector space model (VSM) induced from a domain-specific Oil and Gas corpus, composed of thousands of scientific articles collected from the Elsevier online database. We explore an approach to represent different entities - such as articles, authors and keywords - in the same vector space, making it possible to correlate them and infer relations of similarity based on their cosine distance. An evaluation metric is also provided in order to assist the training process and hyperparameters optimization.\u0000 \u0000 \u0000 \u0000 Oil and Gas highly technical vocabulary represents a challenge to NLP applications, in which some terms may assume a completely different meaning from the general - context domain. In this scenario, gathering an Oil and Gas corpus and training specialized vector space models for this specific domain allows increasing the quality in Technology Intelligence Analysis. The most significant finding is that we were able to explicit the semantic relationships between different entities of interest in the same VSM, also linking these relationships together with some additional metadata. An interesting application is to compare the publications of authors affiliated to two or more O&G companies at a given time. These non-trivial correlations are important to gain strategic insights considering a Technology Intelligence Analysis scenario.\u0000 \u0000 \u0000 \u0000 the novelty of this proposed methodology is the possibility of exploring new insights when correlating different entities in a technology intelligence scenario for the Oil and Gas domain, using a simple yet efficient approach based on document embedding techniques. This method applies some advanced NLP techniques to quickly process more than a hundred thousand documents in a few seconds, without requiring complex hardware resources, which would be impractical using traditional techniques.\u0000","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77940727","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}
U. Bustos, Diana Chaparro, David Alfonso Serrano, Alvaro Chapellin, E. Kovarskiy, Diego Fernando Rodriguez, Heliodoro Cañarete, Juan Carlos Ortiz
Several fields in Colombia are in the maturity phase. While the efforts are mainly focused on workflows and technology incorporation for either increasing hydrocarbon production and/or minimizing water cut, the combination of variable salinities due to production/waterflood with complex mineralogies and shales distributions, is detrimental to a proper saturation assessment with archie methods. The content of clay, thin laminations and small pore sizes add to the rock an important conductivity component that translates into low resistivity responses when measuring with low frequency conductivity devices (either based on induction or laterolog principles) and low contrast between sand and shales. Such formation evaluation issues are detrimental to achieve representative hydrocarbon saturation computations in many interest zones in this case study. In this context, we propose a formation evaluation solution based on wireline dielectric dispersion measurements. Using a 1-inch vertical resolution wireline-conveyed device, we polarize the reservoirs with a multi-frequency electromagnetic field and evaluate the formation response to the application of this field. At higher frequencies, the electronic polarization phenomena enable to displace cloud of atoms in the formation where information on low dielectric constant materials (hydrocarbons, matrix) is assessed. At intermediate frequencies, the molecular polarization occurs by rotating-reorienting the dipoles (water molecules) creating a strong attenuation and phase shift of the electromagnetic field; consequently, allowing to measure salinity and resistivity-independent water volume. Lastly, at lower frequencies the predominance of Maxwell-Wagner effects which are related to the electrical charge redistribution at interfaces due to electromagnetic field application, enable to obtain information on rock textural information (tortuosity and cation exchange capacity). By building a petrophysical model with dielectric dispersion and nuclear logs, we then obtain a high-resolution resistivity and salinity-independent formation evaluation that solves for porosity and water vs oil saturation with a single and fast wireline logging run.
{"title":"Finding New Hydrocarbons in Mature Fields with High Resolution Dielectric Dispersion","authors":"U. Bustos, Diana Chaparro, David Alfonso Serrano, Alvaro Chapellin, E. Kovarskiy, Diego Fernando Rodriguez, Heliodoro Cañarete, Juan Carlos Ortiz","doi":"10.4043/29896-ms","DOIUrl":"https://doi.org/10.4043/29896-ms","url":null,"abstract":"\u0000 Several fields in Colombia are in the maturity phase. While the efforts are mainly focused on workflows and technology incorporation for either increasing hydrocarbon production and/or minimizing water cut, the combination of variable salinities due to production/waterflood with complex mineralogies and shales distributions, is detrimental to a proper saturation assessment with archie methods. The content of clay, thin laminations and small pore sizes add to the rock an important conductivity component that translates into low resistivity responses when measuring with low frequency conductivity devices (either based on induction or laterolog principles) and low contrast between sand and shales. Such formation evaluation issues are detrimental to achieve representative hydrocarbon saturation computations in many interest zones in this case study.\u0000 In this context, we propose a formation evaluation solution based on wireline dielectric dispersion measurements. Using a 1-inch vertical resolution wireline-conveyed device, we polarize the reservoirs with a multi-frequency electromagnetic field and evaluate the formation response to the application of this field. At higher frequencies, the electronic polarization phenomena enable to displace cloud of atoms in the formation where information on low dielectric constant materials (hydrocarbons, matrix) is assessed. At intermediate frequencies, the molecular polarization occurs by rotating-reorienting the dipoles (water molecules) creating a strong attenuation and phase shift of the electromagnetic field; consequently, allowing to measure salinity and resistivity-independent water volume. Lastly, at lower frequencies the predominance of Maxwell-Wagner effects which are related to the electrical charge redistribution at interfaces due to electromagnetic field application, enable to obtain information on rock textural information (tortuosity and cation exchange capacity). By building a petrophysical model with dielectric dispersion and nuclear logs, we then obtain a high-resolution resistivity and salinity-independent formation evaluation that solves for porosity and water vs oil saturation with a single and fast wireline logging run.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83363550","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}
Liang Sun, Liang Wei, Hang Zhao, Baozhu Li, Yong Li
Carbonate reservoirs in the Middle East are characterized by strong heterogeneity, fairly subtle barriers and baffles, which result in low water flood swept volume and poor displacement efficiency. Therefore, optimum well pattern deployment is critical for high-efficiency development of such reservoirs. This paper focuses on a giant carbonate reservoir and discusses the application of highly inclined well to optimizing the deployment of well pattern. In this paper, first, based on the productivity formulae of slanted and horizontal wells proposed by Besson, the adaptability of highly inclined well in giant carbonate reservoir was evaluated. Then, the well design parameters were optimized by using numerical simulation. Finally, the optimum well pattern of "water injection in vertical well and oil production in highly inclined well" was established, and sound development strategies were determined. This provided us the foundation to propose customized water flooding plan. The successful application of this development scheme for M carbonate reservoir in Iraq validated the technical feasibility, which achieved considerable economic benefits. The results indicate that highly inclined well has advantages in productivity and adaptability of well type to this kind of reservoirs. The production of top low-permeability layers and bottom low-permeability layers in M reservoir with inclined interval and horizontal interval respectively makes full use of highly inclined well, which balances injectivity and productivity of different reservoir properties. The proper length of highly inclined well is 2953∼3281 feet, and the ratio of inclined interval to horizontal interval is about 2. The optimized well pattern of "water injection in vertical well and oil production in highly inclined well" improves water injection sweep efficiency and recovery factor. The M reservoir in Iraq has achieved an annual yield of more than 1.5 million barrels. The water injection development for large-scale carbonate reservoirs in the Middle East is still at exploration stage and lack of mature experience. The proposed development pattern in this paper provides a methodology for the efficient development of similar reservoirs.
{"title":"Application of Highly Inclined Well to Optimizing Well Pattern: Case Study of a Giant Carbonate Reservoir in the Middle East","authors":"Liang Sun, Liang Wei, Hang Zhao, Baozhu Li, Yong Li","doi":"10.4043/29942-ms","DOIUrl":"https://doi.org/10.4043/29942-ms","url":null,"abstract":"\u0000 Carbonate reservoirs in the Middle East are characterized by strong heterogeneity, fairly subtle barriers and baffles, which result in low water flood swept volume and poor displacement efficiency. Therefore, optimum well pattern deployment is critical for high-efficiency development of such reservoirs. This paper focuses on a giant carbonate reservoir and discusses the application of highly inclined well to optimizing the deployment of well pattern.\u0000 In this paper, first, based on the productivity formulae of slanted and horizontal wells proposed by Besson, the adaptability of highly inclined well in giant carbonate reservoir was evaluated. Then, the well design parameters were optimized by using numerical simulation. Finally, the optimum well pattern of \"water injection in vertical well and oil production in highly inclined well\" was established, and sound development strategies were determined. This provided us the foundation to propose customized water flooding plan. The successful application of this development scheme for M carbonate reservoir in Iraq validated the technical feasibility, which achieved considerable economic benefits.\u0000 The results indicate that highly inclined well has advantages in productivity and adaptability of well type to this kind of reservoirs. The production of top low-permeability layers and bottom low-permeability layers in M reservoir with inclined interval and horizontal interval respectively makes full use of highly inclined well, which balances injectivity and productivity of different reservoir properties. The proper length of highly inclined well is 2953∼3281 feet, and the ratio of inclined interval to horizontal interval is about 2. The optimized well pattern of \"water injection in vertical well and oil production in highly inclined well\" improves water injection sweep efficiency and recovery factor. The M reservoir in Iraq has achieved an annual yield of more than 1.5 million barrels.\u0000 The water injection development for large-scale carbonate reservoirs in the Middle East is still at exploration stage and lack of mature experience. The proposed development pattern in this paper provides a methodology for the efficient development of similar reservoirs.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88770795","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}
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":"1 1","pages":""},"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}
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":"1 1","pages":""},"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}
D. Obando, F. Fornasier, Ary J. Junior, H. Matos, R. Andrade
In the Peregrino field, located in the Campos Basin offshore Brazil, the operator adopted the use of water-based drilling fluids for drilling development wells due to rig limitations. In the 12 ¼-in. sections of several wells drilled in this field, high dispersion of shale minerals suffered by the drilling fluid caused increments of viscosity, which subsequently affected the drilling process through higher-than-expected circulation pressures, dilution rates, and costs. Although the wells have been drilled within the estimated times and budgets, an improvement in the fluid inhibition capability was initiated. A detailed laboratory effort was conducted to obtain a combination of inhibitors capable of controlling excessive clay dispersion, minimizing fluid rock interaction, and reducing dilution requirements while helping to ensure an adequate rheological profile throughout the interval. Laboratory validation of the interaction between the fluid and rock samples provided a better understanding of the inhibition mechanisms and helped ensure that stability of the reactive minerals drilled could be maintained. Various additives were tested against samples of commercial-reactive and field-reactive clays. Product concentrations were adjusted to reduce the interaction between the drilling fluid and the formation while helping to ensure that fluid capabilities, such as cuttings suspension, filtration control, and bridging, were maintained. An adequate environmental profile to enable safe disposal of fluid in compliance with local environmental regulations was also obtained. After identifying an adequate solution, a detailed utilization plan was developed and put in place. To aid proper deployment while drilling, specific mixing procedures at the support liquid mud plant, transportation vessels, and at the rig site were determined. The next step was to assign a candidate well for the application – an Extended Reach Well (ERW) with step-out ratio of 2.9. While drilling the 12-¼-in. section of the pilot well with the proposed fluid technology, a significant improvement was observed on cuttings integrity, which led to a reduction in the required volume of dilution and a subsequent drilling fluids cost reduction Also, better hole quality and reduced operational risks were obtained. The well was safely drilled with a 76° sail inclination, 7938 meters of Measured Depth (MD) and 2368 meters of True Vertical Depth (TVD), and lessons learned from the first utilization of the described fluid system were implemented on subsequent wells to continue obtaining the benefits of the new fluid formulation. High Performance Water Based Drilling Fluids (HPWBDF) are not new and are thought by most to be a mature technology. However, advancements in water-based drilling fluid additives have enabled these systems to mimic the performance of non-aqueous systems more closely. This paper discusses how understanding the chemistry of the formations to be drilled and customizing
{"title":"Customized High-Performance Water-Based Drilling Fluid Helps Improve Drilling Efficiency in Extended-Reach Wells on the Peregrino Field","authors":"D. Obando, F. Fornasier, Ary J. Junior, H. Matos, R. Andrade","doi":"10.4043/29738-ms","DOIUrl":"https://doi.org/10.4043/29738-ms","url":null,"abstract":"\u0000 In the Peregrino field, located in the Campos Basin offshore Brazil, the operator adopted the use of water-based drilling fluids for drilling development wells due to rig limitations. In the 12 ¼-in. sections of several wells drilled in this field, high dispersion of shale minerals suffered by the drilling fluid caused increments of viscosity, which subsequently affected the drilling process through higher-than-expected circulation pressures, dilution rates, and costs. Although the wells have been drilled within the estimated times and budgets, an improvement in the fluid inhibition capability was initiated.\u0000 A detailed laboratory effort was conducted to obtain a combination of inhibitors capable of controlling excessive clay dispersion, minimizing fluid rock interaction, and reducing dilution requirements while helping to ensure an adequate rheological profile throughout the interval.\u0000 Laboratory validation of the interaction between the fluid and rock samples provided a better understanding of the inhibition mechanisms and helped ensure that stability of the reactive minerals drilled could be maintained. Various additives were tested against samples of commercial-reactive and field-reactive clays. Product concentrations were adjusted to reduce the interaction between the drilling fluid and the formation while helping to ensure that fluid capabilities, such as cuttings suspension, filtration control, and bridging, were maintained. An adequate environmental profile to enable safe disposal of fluid in compliance with local environmental regulations was also obtained.\u0000 After identifying an adequate solution, a detailed utilization plan was developed and put in place. To aid proper deployment while drilling, specific mixing procedures at the support liquid mud plant, transportation vessels, and at the rig site were determined. The next step was to assign a candidate well for the application – an Extended Reach Well (ERW) with step-out ratio of 2.9. While drilling the 12-¼-in. section of the pilot well with the proposed fluid technology, a significant improvement was observed on cuttings integrity, which led to a reduction in the required volume of dilution and a subsequent drilling fluids cost reduction Also, better hole quality and reduced operational risks were obtained. The well was safely drilled with a 76° sail inclination, 7938 meters of Measured Depth (MD) and 2368 meters of True Vertical Depth (TVD), and lessons learned from the first utilization of the described fluid system were implemented on subsequent wells to continue obtaining the benefits of the new fluid formulation.\u0000 High Performance Water Based Drilling Fluids (HPWBDF) are not new and are thought by most to be a mature technology. However, advancements in water-based drilling fluid additives have enabled these systems to mimic the performance of non-aqueous systems more closely. This paper discusses how understanding the chemistry of the formations to be drilled and customizing ","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75585304","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":"25 1","pages":""},"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}
Matheus de Freitas Bezerra, Guilherme Cosme Viganô, J. L. Giuriatto
Nowadays gas-lift is still a very expressive artificial lift method, for instance considering the whole Brazilian oil production profiles, gas lifted wells are responsible for 30% of monthly production. Due this huge importance, the injection efficiency should be ensured to avoid lid gas losses and maximize the production. Then, this study had as objective to develop a Gas Lift Optimization workflow and define the optimum lift rates to increase the reservoir recovery and improve gas usability due to platform constraints of a Brazilian deep-water field. That workflow comprises a reservoir and flow assurance simulators, achieving more accurate responses compared to regular workflows. Taking advantages of the proposed method, multidisciplinary teams could work together which increases the representativeness of such studies providing important outcomes for decision makers. At this study, due to a gas-lift optimization was observed an increase of 0.5% at cumulative production with a huge gas-lift reduction of around 40%, resulting in a better financial balance of the project, saving a considerable amount of lift-gas. The methodology adopted to optimize the injected gas lift rate and consequently increase/maintain cumulative oil production proved adequate for application in oil fields that are highly dependent on artificial lift methods. Therefore, exploration and production projects can be financial healthier.
{"title":"Optimization Methodology of Artificial Lift Rates for Brazilian Offshore Field","authors":"Matheus de Freitas Bezerra, Guilherme Cosme Viganô, J. L. Giuriatto","doi":"10.4043/29889-ms","DOIUrl":"https://doi.org/10.4043/29889-ms","url":null,"abstract":"\u0000 Nowadays gas-lift is still a very expressive artificial lift method, for instance considering the whole Brazilian oil production profiles, gas lifted wells are responsible for 30% of monthly production. Due this huge importance, the injection efficiency should be ensured to avoid lid gas losses and maximize the production. Then, this study had as objective to develop a Gas Lift Optimization workflow and define the optimum lift rates to increase the reservoir recovery and improve gas usability due to platform constraints of a Brazilian deep-water field. That workflow comprises a reservoir and flow assurance simulators, achieving more accurate responses compared to regular workflows. Taking advantages of the proposed method, multidisciplinary teams could work together which increases the representativeness of such studies providing important outcomes for decision makers. At this study, due to a gas-lift optimization was observed an increase of 0.5% at cumulative production with a huge gas-lift reduction of around 40%, resulting in a better financial balance of the project, saving a considerable amount of lift-gas. The methodology adopted to optimize the injected gas lift rate and consequently increase/maintain cumulative oil production proved adequate for application in oil fields that are highly dependent on artificial lift methods. Therefore, exploration and production projects can be financial healthier.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"93 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83820140","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
C. M. D. Jesus, A. Compan, Jéferson Coêlho, Alysson Espindola de Sá Silveira, M. Blauth
The representation of karst petrophysical properties on geologic models has been a challenge, mostly because of the lack of reliable information about the mega and giga pore network, such as large vugs, caves, conduits and enlarged fractures. Since image logs currently have provided the capability of measuring morphological properties in this pore scale, specific techniques have been developed with the objective of obtaining quantitative data that capture these properties. In order to evaluate morphological properties that are representative of mega and giga pores, it is necessary to individually segment each pore structure. A set of computational geometry and image processing techniques were used to measure morphological properties, such as area, perimeter, longest internal path (LIP), internal length (IL), and structure diameter. The area and perimeter of the structure are computed directly on the segmented borehole image log data. The application of this technique allows the classification of different mega and giga pore types. The quantitative evaluation of karst porosity developed in this work has been applied in a brazilian karstified pre-salt carbonate reservoir. The results have shown good correlation with dynamic properties, such as fluid losses while drilling and high productivity intervals measured in production logs. It was possible to identify two distinct correlations between the increase of pore diameter and permeability response of fractured and vuggy-cavy reservoirs. This new technique is helpful for improving the knowledge and representability of the pore scales in order to honor the complexity of the structures generated by the karstification processes. Additionally, new workflows have been developed to incorporate the pore diameters in the geological modeling of karstified reservoirs. The distinct properties of each medium, in the future, might be represented in a model with the assignment of specific fluid mechanics equations, such as Darcys and Hagen-Poiseuilles, for each one. There is a new ground to be gained in fluid flow simulation at these wide ranges of scales and heterogeneous distribution. For that reason, one of the aims of this paper is to stimulate the petrophysical and geological communities towards this goal, as more representative properties of karst porosity heterogeneity become available.
{"title":"Evaluation of Karst Porosity Morphological Properties through Borehole Image Logs – Correlation with Dynamic Reservoir Properties from a presalt Oil Field","authors":"C. M. D. Jesus, A. Compan, Jéferson Coêlho, Alysson Espindola de Sá Silveira, M. Blauth","doi":"10.4043/29722-ms","DOIUrl":"https://doi.org/10.4043/29722-ms","url":null,"abstract":"\u0000 The representation of karst petrophysical properties on geologic models has been a challenge, mostly because of the lack of reliable information about the mega and giga pore network, such as large vugs, caves, conduits and enlarged fractures. Since image logs currently have provided the capability of measuring morphological properties in this pore scale, specific techniques have been developed with the objective of obtaining quantitative data that capture these properties.\u0000 In order to evaluate morphological properties that are representative of mega and giga pores, it is necessary to individually segment each pore structure. A set of computational geometry and image processing techniques were used to measure morphological properties, such as area, perimeter, longest internal path (LIP), internal length (IL), and structure diameter. The area and perimeter of the structure are computed directly on the segmented borehole image log data. The application of this technique allows the classification of different mega and giga pore types.\u0000 The quantitative evaluation of karst porosity developed in this work has been applied in a brazilian karstified pre-salt carbonate reservoir. The results have shown good correlation with dynamic properties, such as fluid losses while drilling and high productivity intervals measured in production logs. It was possible to identify two distinct correlations between the increase of pore diameter and permeability response of fractured and vuggy-cavy reservoirs. This new technique is helpful for improving the knowledge and representability of the pore scales in order to honor the complexity of the structures generated by the karstification processes. Additionally, new workflows have been developed to incorporate the pore diameters in the geological modeling of karstified reservoirs. The distinct properties of each medium, in the future, might be represented in a model with the assignment of specific fluid mechanics equations, such as Darcys and Hagen-Poiseuilles, for each one.\u0000 There is a new ground to be gained in fluid flow simulation at these wide ranges of scales and heterogeneous distribution. For that reason, one of the aims of this paper is to stimulate the petrophysical and geological communities towards this goal, as more representative properties of karst porosity heterogeneity become available.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76832451","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":"9 10 1","pages":""},"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}
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