We study the feasibility of using electrical/EM methods for monitoring the injection of supercritical CO2 at a depth of 1700 m in a saline aquifer of the Paris Basin (Dogger carbonates). We first establish the theoretical interest of resistivity methods for CO2 monitoring through the basic laws of electrical physics in porous sedimentary rocks, assuming that supercritical CO2 is a perfect insulator. Various combinations of EM sources and sensors are discussed and it is shown that the best type of array consists of a galvanic source (i.e. injection of current via a pair of electrodes A and B) and of a grid of electric (and possibly magnetic) sensors at the ground surface. Given the usual depth and thinness of CO2 storage layers, current injection at depth was investigated in order to increase the current density in the reservoir and thus enhance the CO2 response. Point injection at the reservoir depth in the so-called “Mise A la Masse” (MAM) configuration is generally impossible in deep wells due to the presence of metallic casings. Therefore, the possibility of using a deep metallic casing as a long electrode distributing the current all along a borehole is studied. This kind of source is named “LEMAM” (Long Electrode Mise A la Masse) in order to differentiate it from the conventional MAM.Numerical simulations are presented for the LEMAM array and for the gradient or rectangle array (RECT), for which the current is injected by a pair of point electrodes at the ground surface. The geoelectric model used is based on an area close to the Saint-Martin-de-Bossenay (SMB) oilfield, in the south-east of the Paris Basin. The storage reservoir considered in this study is the 75-m-thick “Oolithe Blanche” formation (Mid Jurassic or Dogger, Bathonian age), located at a depth of about 1700 m below ground surface. In the models presented, the CO2 plume is simplified to a square horizontal slab of 2 km side, 70 m thick, floating at the top of the oolite aquifer. A uniform CO2 saturation of 80% is assumed, yielding a resistivity contrast of 25 with the initial reservoir.Two variants of the model with different reservoir resistivities are compared. The first model is calculated with a realistic reservoir resistivity of 20 ohm.m, reflecting the low salinity of the aquifer in this part of the Basin (≈ g g/L of NaCl). With this model, the time-lapse electric response of the CO2 plume is less than 0.5% of the initial electric field, which is below the estimated “repetition noise”. This poor result can be explained by the fact that the reservoir, in this case, is far from being the most conductive layer of the model. As a consequence, only a minor part of the injected current is used for energizing the CO2 plume: a rough calculation shows that only about 2% of the injected current crosses the reservoir, hence the poor response of the plume.A second model is calculated with an idealistic reservoir resistivity of 1 ohm.m, corresponding to about 50-70 g/L of NaCl in the a
我们研究了在巴黎盆地(Dogger碳酸盐)盐层1700米深处使用电/电磁方法监测超临界二氧化碳注入的可行性。我们首先从多孔沉积岩的电物理基本定律出发，假设超临界CO2是完美绝缘体，建立了电阻率法监测CO2的理论兴趣。讨论了电磁源和传感器的各种组合，结果表明，最佳的阵列类型由电源(即通过一对电极a和B注入电流)和地面上的电(可能还有磁)传感器网格组成。考虑到CO2储层通常的深度和厚度，为了增加储层中的电流密度，从而增强CO2响应，研究了深度注入电流的方法。在深井中，由于金属套管的存在，在所谓的“Mise A la Masse”(MAM)配置的油藏深度点注入通常是不可能的。因此，研究了利用深金属套管作为沿钻孔分布电流的长电极的可能性。这种源被命名为“LEMAM”(长电极Mise A la Masse)，以区别于传统的MAM。给出了leam阵列和梯度或矩形阵列(RECT)的数值模拟，其中电流由地面上的一对点电极注入。所使用的地电模型是基于位于巴黎盆地东南部的Saint-Martin-de-Bossenay (SMB)油田附近的区域。本研究考虑的储层为75米厚的“Oolithe Blanche”组(中侏罗世或多格尔，Bathonian时代)，位于地表以下约1700米的深度。在所提出的模型中，CO2羽流被简化为一个边长2公里、厚70米的方形水平板，漂浮在鲕粒含水层顶部。假设CO2均匀饱和度为80%，与初始储层的电阻率对比为25。对具有不同储层电阻率的两种模型进行了比较。第一个模型是用20欧姆的实际储层电阻率计算的。m，反映了该盆地部分含水层盐度较低(≈g g/L NaCl)。利用该模型，CO2羽流的时移电响应小于初始电场的0.5%，低于估计的“重复噪声”。这种糟糕的结果可以用这样一个事实来解释，即在这种情况下，储层远非模型中最导电的层。因此，只有一小部分注入电流被用于激励CO2羽流:粗略计算表明，只有约2%的注入电流穿过储层，因此羽流的响应很差。第二个模型以理想的储层电阻率为1欧姆计算。m，相当于含水层中约50-70 g/L的NaCl(尽管在巴黎盆地的Dogger含水层中没有任何地方观察到这种盐度，但在许多蓄水含水层中很常见)。在这种有利的模型下，估计大约30%的注入电流穿过储层并激活羽流，导致高达初始电场6%的延时电响应，这是相当可测量的。相比之下，使用相同模型的表面电流注入(RECT阵列)获得的时移电响应仅为初始场的2%。在相同的模型下，LEMAM注入的时移磁响应约为初始磁场的3%。我们得出的结论是，只要水的盐度足够高，使得储层能够引导相当一部分注入电流(例如> 10%)，LEMAM阵列就非常有希望用于深层含水层二氧化碳注入的电阻率监测。
{"title":"First Modelling Results of the EM Response of a CO2 Storage in the Paris Basin","authors":"B. Bourgeois, J. Girard","doi":"10.2516/OGST/2009076","DOIUrl":"https://doi.org/10.2516/OGST/2009076","url":null,"abstract":"We study the feasibility of using electrical/EM methods for monitoring the injection of supercritical CO2 at a depth of 1700 m in a saline aquifer of the Paris Basin (Dogger carbonates). We first establish the theoretical interest of resistivity methods for CO2 monitoring through the basic laws of electrical physics in porous sedimentary rocks, assuming that supercritical CO2 is a perfect insulator. Various combinations of EM sources and sensors are discussed and it is shown that the best type of array consists of a galvanic source (i.e. injection of current via a pair of electrodes A and B) and of a grid of electric (and possibly magnetic) sensors at the ground surface. Given the usual depth and thinness of CO2 storage layers, current injection at depth was investigated in order to increase the current density in the reservoir and thus enhance the CO2 response. Point injection at the reservoir depth in the so-called “Mise A la Masse” (MAM) configuration is generally impossible in deep wells due to the presence of metallic casings. Therefore, the possibility of using a deep metallic casing as a long electrode distributing the current all along a borehole is studied. This kind of source is named “LEMAM” (Long Electrode Mise A la Masse) in order to differentiate it from the conventional MAM.Numerical simulations are presented for the LEMAM array and for the gradient or rectangle array (RECT), for which the current is injected by a pair of point electrodes at the ground surface. The geoelectric model used is based on an area close to the Saint-Martin-de-Bossenay (SMB) oilfield, in the south-east of the Paris Basin. The storage reservoir considered in this study is the 75-m-thick “Oolithe Blanche” formation (Mid Jurassic or Dogger, Bathonian age), located at a depth of about 1700 m below ground surface. In the models presented, the CO2 plume is simplified to a square horizontal slab of 2 km side, 70 m thick, floating at the top of the oolite aquifer. A uniform CO2 saturation of 80% is assumed, yielding a resistivity contrast of 25 with the initial reservoir.Two variants of the model with different reservoir resistivities are compared. The first model is calculated with a realistic reservoir resistivity of 20 ohm.m, reflecting the low salinity of the aquifer in this part of the Basin (≈ g g/L of NaCl). With this model, the time-lapse electric response of the CO2 plume is less than 0.5% of the initial electric field, which is below the estimated “repetition noise”. This poor result can be explained by the fact that the reservoir, in this case, is far from being the most conductive layer of the model. As a consequence, only a minor part of the injected current is used for energizing the CO2 plume: a rough calculation shows that only about 2% of the injected current crosses the reservoir, hence the poor response of the plume.A second model is calculated with an idealistic reservoir resistivity of 1 ohm.m, corresponding to about 50-70 g/L of NaCl in the a","PeriodicalId":19444,"journal":{"name":"Oil & Gas Science and Technology-revue De L Institut Francais Du Petrole","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2010-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86603113","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 technical and economical success of a CO2 geological storage project requires the preservation of the site injectivity and integrity properties over its lifetime. Unlike conventional hydrocarbon gas injection, CO2 injection implies geochemical reactions between the reactive brine and the in situ formations (reservoir and cap rock) leading to modifications of their petrophysical and geomechanical properties. This paper underlines the experimental difficulties raised by the low permeability of samples representative either of the cap rock itself or at least of transition zones between the reservoir and the effective cap rock. Acidification effects induced by CO2 injection have been studied using an experimental procedure of chemical alteration, which ensures a homogeneous dissolution pattern throughout the rock sample and especially avoids any wormholing process that would lead to erroneous measurements at the core scale. Porosity, permeability and geomechanical properties of outcrop and field carbonate samples of various permeability levels have been measured under their native state and different levels of alteration. The present work has been conducted within the framework of ANR GeoCarbone-INJECTIVITY and GeoCarbone-INTEGRITY projects. Each experimental step: chemical alteration, petrophysical measurements and geomechanical testing, is considered from the point of view of injectivity and integrity issues. The obtained experimental data show clear trends of chemically induced mechanical weakening.
{"title":"From Injectivity to Integrity Studies of CO2 Geological Storage - Chemical Alteration Effects on Carbonates Petrophysical and Geomechanical Properties","authors":"E. Bemer, J. Lombard","doi":"10.2516/OGST/2009028","DOIUrl":"https://doi.org/10.2516/OGST/2009028","url":null,"abstract":"The technical and economical success of a CO2 geological storage project requires the preservation of the site injectivity and integrity properties over its lifetime. Unlike conventional hydrocarbon gas injection, CO2 injection implies geochemical reactions between the reactive brine and the in situ formations (reservoir and cap rock) leading to modifications of their petrophysical and geomechanical properties. This paper underlines the experimental difficulties raised by the low permeability of samples representative either of the cap rock itself or at least of transition zones between the reservoir and the effective cap rock. Acidification effects induced by CO2 injection have been studied using an experimental procedure of chemical alteration, which ensures a homogeneous dissolution pattern throughout the rock sample and especially avoids any wormholing process that would lead to erroneous measurements at the core scale. Porosity, permeability and geomechanical properties of outcrop and field carbonate samples of various permeability levels have been measured under their native state and different levels of alteration. The present work has been conducted within the framework of ANR GeoCarbone-INJECTIVITY and GeoCarbone-INTEGRITY projects. Each experimental step: chemical alteration, petrophysical measurements and geomechanical testing, is considered from the point of view of injectivity and integrity issues. The obtained experimental data show clear trends of chemically induced mechanical weakening.","PeriodicalId":19444,"journal":{"name":"Oil & Gas Science and Technology-revue De L Institut Francais Du Petrole","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2010-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86226647","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}
This work presents a numerical strategy of large scale hydromechanical simulations to assess the risk of damage in caprock formations during a CO2 injection process. The proposed methodology is based on the development of a sequential coupling between a multiphase fluid flow (TOUGH2) and a hydromechanical calculation code (Code_Aster) that enables us to perform coupled hydromechanical simulation at a regional scale. The likelihood of different caprock damage mechanisms can then be evaluated based on the results of the coupled simulations. A scenario based approach is proposed to take into account the effect of the uncertainty of model parameters on damage likelihood. The developed methodology is applied for the caprock failure analysis of deep aquifer of the Dogger formation in the context of the Paris basin multilayered geological system as a demonstration example. The simulation is carried out at a regional scale (100 km) considering an industrial mass injection rate of CO2 of 10 Mt/y. The assessment of the stress state after 10 years of injection is conducted through the developed sequential coupling. Two failure mechanisms have been taken into account, namely the tensile fracturing and the shear slip reactivation of pre-existing fractures. To deal with the large uncertainties due to sparse data on the layer formations, a scenariobased strategy is undertaken. It consists in defining a first reference modelling scenario considering the mean values of the hydromechanical properties for each layer. A sensitivity analysis is then carried out and shows the importance of both the initial stress state and the reservoir hydraulic properties on the caprock failure tendency. On this basis, a second scenario denoted “critical” is defined so that the most influential model parameters are taken in their worst configuration. None of these failure criteria is activated for the considered conditions. At a phenomenological level, this study points out three key aspects for risk management. The maximum overpressure is reached rapidly after a couple of years, the lateral extension of the “overpressurized” zone induced by the injection is very large (> 50 km) and the most critical zone is the injection near zone (distance < 100 m) at the interface between the caprock and the reservoir layer.
{"title":"Coupled Large Scale Hydromechanical Modelling for Caprock Failure Risk Assessment of CO2 Storage in Deep Saline Aquifers","authors":"J. Rohmer, D. Seyedi","doi":"10.2516/OGST/2009049","DOIUrl":"https://doi.org/10.2516/OGST/2009049","url":null,"abstract":"This work presents a numerical strategy of large scale hydromechanical simulations to assess the risk of damage in caprock formations during a CO2 injection process. The proposed methodology is based on the development of a sequential coupling between a multiphase fluid flow (TOUGH2) and a hydromechanical calculation code (Code_Aster) that enables us to perform coupled hydromechanical simulation at a regional scale. The likelihood of different caprock damage mechanisms can then be evaluated based on the results of the coupled simulations. A scenario based approach is proposed to take into account the effect of the uncertainty of model parameters on damage likelihood. The developed methodology is applied for the caprock failure analysis of deep aquifer of the Dogger formation in the context of the Paris basin multilayered geological system as a demonstration example. The simulation is carried out at a regional scale (100 km) considering an industrial mass injection rate of CO2 of 10 Mt/y. The assessment of the stress state after 10 years of injection is conducted through the developed sequential coupling. Two failure mechanisms have been taken into account, namely the tensile fracturing and the shear slip reactivation of pre-existing fractures. To deal with the large uncertainties due to sparse data on the layer formations, a scenariobased strategy is undertaken. It consists in defining a first reference modelling scenario considering the mean values of the hydromechanical properties for each layer. A sensitivity analysis is then carried out and shows the importance of both the initial stress state and the reservoir hydraulic properties on the caprock failure tendency. On this basis, a second scenario denoted “critical” is defined so that the most influential model parameters are taken in their worst configuration. None of these failure criteria is activated for the considered conditions. At a phenomenological level, this study points out three key aspects for risk management. The maximum overpressure is reached rapidly after a couple of years, the lateral extension of the “overpressurized” zone induced by the injection is very large (> 50 km) and the most critical zone is the injection near zone (distance < 100 m) at the interface between the caprock and the reservoir layer.","PeriodicalId":19444,"journal":{"name":"Oil & Gas Science and Technology-revue De L Institut Francais Du Petrole","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2010-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90883599","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
E. Brosse, G. Badinier, François Blanchard, E. Caspard, P. Collin, J. Delmas, C. Dezayes, R. Dreux, A. Dufournet, P. Durst, S. Fillacier, D. Garcia, S. Grataloup, F. Hanot, V. Hasanov, P. Houel, C. Kervévan, M. Lansiart, M. Lescanne, A. Menjoz, M. Monnet, P. Mougin, B. Nedelec, A. Poutrel, X. Rachez, P. Renoux, C. Rigollet, V. Ruffier-Meray, S. Saysset, I. Thinon, A. Thoraval, S. Vidal-Gilbert
The objective of the GeoCarbone-PICOREF project was to select and characterize geological sites where CO2 storage in permeable reservoir could be tested at the pilot scale. Both options of storage in deep saline aquifer and in depleted hydrocarbon field were considered. The typical size envisioned for the pilot was 100 kt CO2 per year. GeoCarbone-PICOREF initially focused on a “Regional Domain”, ca. 200 × 150 km, in the Paris Basin. It was attractive for the following reasons: detailed geological data is available, due to 50 years of petroleum exploration; basin-scale deep saline aquifers are present, with a preliminary estimate of storage capacity which is at the Gt CO2 level, namely the carbonate Oolithe Blanche Formation, of Middle Jurassic age, generally located between 1500 and 1800 m depths in the studied area, and several sandstone formations of Triassic age, located between 2000 and 3000 m; several depleted oil fields exist: although offering storage capacities at a much lower level, they do represent very well constrained geological environments, with proven sealing properties; several sources of pure CO2 were identified in the area, at a flow rate compatible with the pilot size, that would avoid capture costs. 750 km of seismic lines were reprocessed and organized in six sections fitted on well logs. This first dataset provided improved representations of: the gross features of the considered aquifers in the Regional Domain; the structural scheme; lateral continuity of the sealing cap rocks. An inventory of the environmental characteristics was also made, including human occupancy, protected areas, water resource, natural hazards, potential conflicts of use with other resources of the subsurface, etc. From all these criteria, a more restricted geographical domain named the “Sector”, ca. 70 × 70 km, was chosen, the most appropriate for further selection of storage site(s). The geological characterization of the Sector has been as exhaustive as possible, with the reprocessing of additional 450 km of seismic lines, and the collection of a complete well-data base (146 petroleum wells). At this scale a relatively detailed characterization of the sedimentary layers could be done, in particular the formations potentially rich in aquifer units. For the Middle Jurassic carbonates observations were made on analogue sediments outcropping 150 km to the east of the Sector. A geological and numerical 3-D representation of the whole sedimentary pile of the Sector area was built. It forms a basis for constructing grids used by codes able to simulate various processes induced by CO2 injection (displacement of the fluids, pressure build-up and release, mechanical deformation, mineral interactions, control of the parameters used to check the local sealing efficiency, etc.). In parallel with that work on aquifers, GeoCarbone-PICOREF has access to all the petroleum data, including production data and reservoir modelling, of the Saint-Martin de Bossenay oil
{"title":"Selection and Characterization of Geological Sites able to Host a Pilot-Scale CO2 Storage in the Paris Basin (GéoCarbone-PICOREF)","authors":"E. Brosse, G. Badinier, François Blanchard, E. Caspard, P. Collin, J. Delmas, C. Dezayes, R. Dreux, A. Dufournet, P. Durst, S. Fillacier, D. Garcia, S. Grataloup, F. Hanot, V. Hasanov, P. Houel, C. Kervévan, M. Lansiart, M. Lescanne, A. Menjoz, M. Monnet, P. Mougin, B. Nedelec, A. Poutrel, X. Rachez, P. Renoux, C. Rigollet, V. Ruffier-Meray, S. Saysset, I. Thinon, A. Thoraval, S. Vidal-Gilbert","doi":"10.2516/OGST/2009085","DOIUrl":"https://doi.org/10.2516/OGST/2009085","url":null,"abstract":"The objective of the GeoCarbone-PICOREF project was to select and characterize geological sites where CO2 storage in permeable reservoir could be tested at the pilot scale. Both options of storage in deep saline aquifer and in depleted hydrocarbon field were considered. The typical size envisioned for the pilot was 100 kt CO2 per year. GeoCarbone-PICOREF initially focused on a “Regional Domain”, ca. 200 × 150 km, in the Paris Basin. It was attractive for the following reasons: detailed geological data is available, due to 50 years of petroleum exploration; basin-scale deep saline aquifers are present, with a preliminary estimate of storage capacity which is at the Gt CO2 level, namely the carbonate Oolithe Blanche Formation, of Middle Jurassic age, generally located between 1500 and 1800 m depths in the studied area, and several sandstone formations of Triassic age, located between 2000 and 3000 m; several depleted oil fields exist: although offering storage capacities at a much lower level, they do represent very well constrained geological environments, with proven sealing properties; several sources of pure CO2 were identified in the area, at a flow rate compatible with the pilot size, that would avoid capture costs. 750 km of seismic lines were reprocessed and organized in six sections fitted on well logs. This first dataset provided improved representations of: the gross features of the considered aquifers in the Regional Domain; the structural scheme; lateral continuity of the sealing cap rocks. An inventory of the environmental characteristics was also made, including human occupancy, protected areas, water resource, natural hazards, potential conflicts of use with other resources of the subsurface, etc. From all these criteria, a more restricted geographical domain named the “Sector”, ca. 70 × 70 km, was chosen, the most appropriate for further selection of storage site(s). The geological characterization of the Sector has been as exhaustive as possible, with the reprocessing of additional 450 km of seismic lines, and the collection of a complete well-data base (146 petroleum wells). At this scale a relatively detailed characterization of the sedimentary layers could be done, in particular the formations potentially rich in aquifer units. For the Middle Jurassic carbonates observations were made on analogue sediments outcropping 150 km to the east of the Sector. A geological and numerical 3-D representation of the whole sedimentary pile of the Sector area was built. It forms a basis for constructing grids used by codes able to simulate various processes induced by CO2 injection (displacement of the fluids, pressure build-up and release, mechanical deformation, mineral interactions, control of the parameters used to check the local sealing efficiency, etc.). In parallel with that work on aquifers, GeoCarbone-PICOREF has access to all the petroleum data, including production data and reservoir modelling, of the Saint-Martin de Bossenay oil ","PeriodicalId":19444,"journal":{"name":"Oil & Gas Science and Technology-revue De L Institut Francais Du Petrole","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2010-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87789401","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}
This article, carried out as part of the PICOREF Project for the CO2 storage in the aquifers of the Paris Basin, presents an important petrophysical database from the numerous petroleum wells drilled in the PICOREF Sector (south-eastern part of the Paris Basin) between 1953 and 2001. These core data concern the three saline carbonated aquifers of the Middle Jurassic: the Oolithe Blanche and the Comblanchien formations, Upper Bathonian age, and the Dalle Nacree formation, Lower Callovian age, that would be used for the CO2 sequestration. Located at –1230 to –1750 m sub sea in the studied sector, these carbonate reservoirs which cumulative thickness is about 150 m, outcrop in the Burgundy region, at about 80 km south-eastern the Sector where they are exploited in several quarries. The analysis of the 6800 routine measurements (porosity and permeability) gathered for this study allowed to improve the knowledge of the petrophysical properties. Special measurements (mercury injection tests) allowed to characterize the porous medium.
{"title":"Petrophysical Properties of the Middle Jurassic Carbonates in the PICOREF Sector (South Champagne, Paris Basin, France)","authors":"J. Delmas, E. Brosse, P. Houel","doi":"10.2516/OGST/2010002","DOIUrl":"https://doi.org/10.2516/OGST/2010002","url":null,"abstract":"This article, carried out as part of the PICOREF Project for the CO2 storage in the aquifers of the Paris Basin, presents an important petrophysical database from the numerous petroleum wells drilled in the PICOREF Sector (south-eastern part of the Paris Basin) between 1953 and 2001. These core data concern the three saline carbonated aquifers of the Middle Jurassic: the Oolithe Blanche and the Comblanchien formations, Upper Bathonian age, and the Dalle Nacree formation, Lower Callovian age, that would be used for the CO2 sequestration. Located at –1230 to –1750 m sub sea in the studied sector, these carbonate reservoirs which cumulative thickness is about 150 m, outcrop in the Burgundy region, at about 80 km south-eastern the Sector where they are exploited in several quarries. The analysis of the 6800 routine measurements (porosity and permeability) gathered for this study allowed to improve the knowledge of the petrophysical properties. Special measurements (mercury injection tests) allowed to characterize the porous medium.","PeriodicalId":19444,"journal":{"name":"Oil & Gas Science and Technology-revue De L Institut Francais Du Petrole","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2010-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76835154","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 efficiency of geological storage of CO2 lies in the confinement properties of the caprock. Among these properties, diffusive characteristics play an important, though sometimes underestimated, role. Although diffusion is a slow process, it can play a significant role in the long run. Besides, the desirable properties for a caprock – mainly high entry pressure and low permeability – are by no means contradictory with relatively high diffusion coefficients; the reason is that all these quantities do not depend on the same geometrical properties of the porous matrix (pore size in one case, tortuosity in the other). Within the framework of the Geocarbone-INTEGRITE project, financed by the National Research Agency ANR from 2006 to 2008, the diffusion coefficients for water and bicarbonate ions have been measured in caprock samples from three levels (Comblanchien and Dalle Nacree formations). These two species cover the main situations encountered in storage site conditions (neutral/charged species, interacting or not with the solid matrix). The model used for interpretation of the experiments is presented; this enables review of various quantities of interest: effective diffusion coefficient, pore diffusion coefficient, apparent diffusion coefficient, retardation factor. The pore self-diffusion coefficient for water was measured by two different techniques (Nuclear Magnetic Resonance and tritiated water 1 H3 HO tracing) on two samples. The results are comparable: porosity about 6%, pore diffusion coefficient 2 × 10−10 m2 /s, tortuosity about 10. The radioactive tracer method is then applied with tritiated water and carbon-14-tagged bicarbonate ions, H1 CO- 3 , to samples from three depth levels. Reduction of accessible porosity is evidenced for bicarbonate ions, which is attributed to anionic exclusion. Interaction between bicarbonate ions and the solid matrix is also shown. This suggests that additional CO2 storage capacity might be offered by carbonated caprocks (regardless of the problem of alteration by acidified water, not addressed here). Lastly, a few simple rules for extending the results presented here to other experimental conditions are proposed.
{"title":"Diffusion Properties of Carbonated Caprocks from the Paris Basin","authors":"P. Berne, P. Bachaud, M. Fleury","doi":"10.2516/OGST/2009072","DOIUrl":"https://doi.org/10.2516/OGST/2009072","url":null,"abstract":"The efficiency of geological storage of CO2 lies in the confinement properties of the caprock. Among these properties, diffusive characteristics play an important, though sometimes underestimated, role. Although diffusion is a slow process, it can play a significant role in the long run. Besides, the desirable properties for a caprock – mainly high entry pressure and low permeability – are by no means contradictory with relatively high diffusion coefficients; the reason is that all these quantities do not depend on the same geometrical properties of the porous matrix (pore size in one case, tortuosity in the other). Within the framework of the Geocarbone-INTEGRITE project, financed by the National Research Agency ANR from 2006 to 2008, the diffusion coefficients for water and bicarbonate ions have been measured in caprock samples from three levels (Comblanchien and Dalle Nacree formations). These two species cover the main situations encountered in storage site conditions (neutral/charged species, interacting or not with the solid matrix). The model used for interpretation of the experiments is presented; this enables review of various quantities of interest: effective diffusion coefficient, pore diffusion coefficient, apparent diffusion coefficient, retardation factor. The pore self-diffusion coefficient for water was measured by two different techniques (Nuclear Magnetic Resonance and tritiated water 1 H3 HO tracing) on two samples. The results are comparable: porosity about 6%, pore diffusion coefficient 2 × 10−10 m2 /s, tortuosity about 10. The radioactive tracer method is then applied with tritiated water and carbon-14-tagged bicarbonate ions, H1 CO- 3 , to samples from three depth levels. Reduction of accessible porosity is evidenced for bicarbonate ions, which is attributed to anionic exclusion. Interaction between bicarbonate ions and the solid matrix is also shown. This suggests that additional CO2 storage capacity might be offered by carbonated caprocks (regardless of the problem of alteration by acidified water, not addressed here). Lastly, a few simple rules for extending the results presented here to other experimental conditions are proposed.","PeriodicalId":19444,"journal":{"name":"Oil & Gas Science and Technology-revue De L Institut Francais Du Petrole","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2010-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87521617","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
O. Bildstein, C. Kervévan, V. Lagneau, P. Delaplace, A. Credoz, P. Audigane, E. Perfetti, N. Jacquemet, M. Jullien
The objective of the “Geocarbone-Integrite” project (2005-2008) was to develop a methodology to assess the integrity of the caprock involved in the geological storage of CO2 . A specific work package of the project (WP5) was dedicated to the integration of (1) the phenomenology describing the evolution of the storage system with a focus on the mechanisms occurring in the caprock and at the interface with the caprock, and (2) the data obtained from the investigation of petrographical, geomechanical, and geochemical properties, before and after reaction with CO2 -rich solutions, performed in the other work packages (WP1 to WP4). This knowledge was introduced in numerical models and specific safety scenarios were defined in order to assess the performance of the CO2 storage system.The results of the modeling show that the injection of CO2 can potentially have a significant effect on the caprock by changing the porosity due to the dissolution and precipitation of minerals, but that the impact is limited to a zone from several decimeters to several meters of the caprock close to the interface with the reservoir depending on whether the supercritical carbon dioxide (SC-CO2 ) plume enters into the caprock and if fractures are present at this location.The methodology used in this project can be applied to a pilot site for the injection of CO2 in the Paris Basin. A key aspect of the safety of such a facility will be to look at the coupling of geochemical alteration and the evolution of geomechanical properties in the short and medium terms (several hundreds of years). The challenge for the future will be to structure and apply the safety assessment methodology with an operational finality, in order to support the robustness of the transition step to CGS projects at the industrial scale.
{"title":"Integrative Modeling of Caprock Integrity in the Context of CO2 Storage: Evolution of Transport and Geochemical Properties and Impact on Performance and Safety Assessment","authors":"O. Bildstein, C. Kervévan, V. Lagneau, P. Delaplace, A. Credoz, P. Audigane, E. Perfetti, N. Jacquemet, M. Jullien","doi":"10.2516/OGST/2010006","DOIUrl":"https://doi.org/10.2516/OGST/2010006","url":null,"abstract":"The objective of the “Geocarbone-Integrite” project (2005-2008) was to develop a methodology to assess the integrity of the caprock involved in the geological storage of CO2 . A specific work package of the project (WP5) was dedicated to the integration of (1) the phenomenology describing the evolution of the storage system with a focus on the mechanisms occurring in the caprock and at the interface with the caprock, and (2) the data obtained from the investigation of petrographical, geomechanical, and geochemical properties, before and after reaction with CO2 -rich solutions, performed in the other work packages (WP1 to WP4). This knowledge was introduced in numerical models and specific safety scenarios were defined in order to assess the performance of the CO2 storage system.The results of the modeling show that the injection of CO2 can potentially have a significant effect on the caprock by changing the porosity due to the dissolution and precipitation of minerals, but that the impact is limited to a zone from several decimeters to several meters of the caprock close to the interface with the reservoir depending on whether the supercritical carbon dioxide (SC-CO2 ) plume enters into the caprock and if fractures are present at this location.The methodology used in this project can be applied to a pilot site for the injection of CO2 in the Paris Basin. A key aspect of the safety of such a facility will be to look at the coupling of geochemical alteration and the evolution of geomechanical properties in the short and medium terms (several hundreds of years). The challenge for the future will be to structure and apply the safety assessment methodology with an operational finality, in order to support the robustness of the transition step to CGS projects at the industrial scale.","PeriodicalId":19444,"journal":{"name":"Oil & Gas Science and Technology-revue De L Institut Francais Du Petrole","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2010-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85940579","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}
P. Carles, P. Bachaud, E. Lasseur, P. Berne, P. Bretonnier
Le projet Geocarbone-Integrite, finance par l'Agence Nationale de la Recherche (ANR) de 2006 a 2008, vise a developper les connaissances et les techniques necessaires a la prevision de l'efficacite et la securite du confinement sur le long terme des stockages geologiques de CO2. La premiere tâche a ete de caracteriser a l'echelle petrographique, les facies carbonates du sommet du Dogger appartenant aux formations des Calcaires du Comblanchien et de la Dalle Nacree, situees mmediatement au-dessus des niveaux reservoirs retenus comme potentiels sites de stockage. Une etude petrophysique precise des facies de couvertures potentielles est realisee. La porosite, la distribution de taille de pores et la permeabilite sont determinees en utilisant des methodes adaptees a des milieux tres peu permeables (<10 microDarcy). Les permeabilites sont mesurees a l'azote, a l'helium et a la saumure sous pression de confinement avec la methode stationnaire et la methode transitoire. Les porosites sont faibles et varient de 2 a 9 % suivant le facies, et les permeabilites en monophasique varient de 0,3 a 20 microDarcy. Le fait d'utiliser plusieurs techniques de mesure de porosite et permeabilite permet d'evaluer l'incertitude des resultats. La pression capillaire de seuil est estimee par les courbes d'injection de mercure (Purcell). L'estimation a partir des courbes de Purcell est sujette aux incertitudes (choix des tensions interfaciales et du point d'entree du mercure) et ne remplace donc pas une mesure directe de pression de seuil. La pression de seuil est donc aussi mesuree sur carotte en conditions in situ avec de l'azote (N2) et du dioxyde de carbone (CO2), pour voir l'effet du CO2 sur la pression d'entree par rapport a un gaz neutre. Deux methodes sont utilisees, la methode classique par paliers de pression et la methode dynamique. La methode dynamique est basee sur la reduction de debit de saumure en sortie de l'echantillon lorsque le gaz commence a penetrer a l'entree de l'echantillon sature en saumure. Chacune de ces methodes possede des avantages et des limites d'application mis en exergue dans le cadre de cette etude. Pour le systeme CO2/saumure les valeurs de pressions de seuil mesurees vont de 0,4 a 22 bar suivant les facies. Les valeurs de Pth, meme pour le facies le plus compact, sont probablement trop faibles pour que l'on puisse exclure une penetration du CO2 dans la roche de couverture. Cette constatation n'interdit toutefois pas d'envisager un stockage de CO2, dans la mesure ou on peut montrer que la permeabilite de la couverture est suffisamment faible, et son epaisseur suffisamment grande, pour que cette penetration reste limitee malgre le maintien de la surpression sur la duree
{"title":"Confining Properties of Carbonated Dogger Caprocks (Parisian Basin) for CO2 Storage Purpose","authors":"P. Carles, P. Bachaud, E. Lasseur, P. Berne, P. Bretonnier","doi":"10.2516/OGST/2009082","DOIUrl":"https://doi.org/10.2516/OGST/2009082","url":null,"abstract":"Le projet Geocarbone-Integrite, finance par l'Agence Nationale de la Recherche (ANR) de 2006 a 2008, vise a developper les connaissances et les techniques necessaires a la prevision de l'efficacite et la securite du confinement sur le long terme des stockages geologiques de CO2. La premiere tâche a ete de caracteriser a l'echelle petrographique, les facies carbonates du sommet du Dogger appartenant aux formations des Calcaires du Comblanchien et de la Dalle Nacree, situees mmediatement au-dessus des niveaux reservoirs retenus comme potentiels sites de stockage. Une etude petrophysique precise des facies de couvertures potentielles est realisee. La porosite, la distribution de taille de pores et la permeabilite sont determinees en utilisant des methodes adaptees a des milieux tres peu permeables (<10 microDarcy). Les permeabilites sont mesurees a l'azote, a l'helium et a la saumure sous pression de confinement avec la methode stationnaire et la methode transitoire. Les porosites sont faibles et varient de 2 a 9 % suivant le facies, et les permeabilites en monophasique varient de 0,3 a 20 microDarcy. Le fait d'utiliser plusieurs techniques de mesure de porosite et permeabilite permet d'evaluer l'incertitude des resultats. La pression capillaire de seuil est estimee par les courbes d'injection de mercure (Purcell). L'estimation a partir des courbes de Purcell est sujette aux incertitudes (choix des tensions interfaciales et du point d'entree du mercure) et ne remplace donc pas une mesure directe de pression de seuil. La pression de seuil est donc aussi mesuree sur carotte en conditions in situ avec de l'azote (N2) et du dioxyde de carbone (CO2), pour voir l'effet du CO2 sur la pression d'entree par rapport a un gaz neutre. Deux methodes sont utilisees, la methode classique par paliers de pression et la methode dynamique. La methode dynamique est basee sur la reduction de debit de saumure en sortie de l'echantillon lorsque le gaz commence a penetrer a l'entree de l'echantillon sature en saumure. Chacune de ces methodes possede des avantages et des limites d'application mis en exergue dans le cadre de cette etude. Pour le systeme CO2/saumure les valeurs de pressions de seuil mesurees vont de 0,4 a 22 bar suivant les facies. Les valeurs de Pth, meme pour le facies le plus compact, sont probablement trop faibles pour que l'on puisse exclure une penetration du CO2 dans la roche de couverture. Cette constatation n'interdit toutefois pas d'envisager un stockage de CO2, dans la mesure ou on peut montrer que la permeabilite de la couverture est suffisamment faible, et son epaisseur suffisamment grande, pour que cette penetration reste limitee malgre le maintien de la surpression sur la duree","PeriodicalId":19444,"journal":{"name":"Oil & Gas Science and Technology-revue De L Institut Francais Du Petrole","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2010-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91387099","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}
Naturally fractured reservoirs contain a significant amount of the world oil reserves. The production of this type of reservoirs constitutes a challenge for reservoir engineers. Use of reservoir simulators can help reservoir engineers in the understanding of the main physical mechanisms and in the choice of the best recovery process and its optimization. Significant progress has been made since the first publications on the dual-porosity concept in the sixties. This paper and the preceding one (Part 1) present the current techniques of modeling used in industrial simulators. The optimal way to predict matrix-fracture transfers at the simulator cell scale has no definite answer and various methods are implemented in industrial simulators. This paper focuses on the modeling of physical mechanisms driving flows and interactions/ exchanges within and between fracture and matrix media for a better understanding of proposed flow formula and simulation methods. Typical features of fractured reservoir numerical simulations are also described with an overview of the implementation of geomechanics effects, an application of uncertainty assessment methodology to a fractured gas reservoir and finally a presentation of a history matching methodology for fractured reservoirs.
{"title":"Simulation of Naturally Fractured Reservoirs. State of the Art - Part 2 – Matrix-Fracture Transfers and Typical Features of Numerical Studies","authors":"P. Lemonnier, B. Bourbiaux","doi":"10.2516/OGST/2009067","DOIUrl":"https://doi.org/10.2516/OGST/2009067","url":null,"abstract":"Naturally fractured reservoirs contain a significant amount of the world oil reserves. The production of this type of reservoirs constitutes a challenge for reservoir engineers. Use of reservoir simulators can help reservoir engineers in the understanding of the main physical mechanisms and in the choice of the best recovery process and its optimization. Significant progress has been made since the first publications on the dual-porosity concept in the sixties. This paper and the preceding one (Part 1) present the current techniques of modeling used in industrial simulators. The optimal way to predict matrix-fracture transfers at the simulator cell scale has no definite answer and various methods are implemented in industrial simulators. This paper focuses on the modeling of physical mechanisms driving flows and interactions/ exchanges within and between fracture and matrix media for a better understanding of proposed flow formula and simulation methods. Typical features of fractured reservoir numerical simulations are also described with an overview of the implementation of geomechanics effects, an application of uncertainty assessment methodology to a fractured gas reservoir and finally a presentation of a history matching methodology for fractured reservoirs.","PeriodicalId":19444,"journal":{"name":"Oil & Gas Science and Technology-revue De L Institut Francais Du Petrole","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2010-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75916918","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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