Experimental and numerical investigations on CO2 injection and enhanced gas recovery effects in Altmark gas field (Central Germany)     

Leonhard Ganzer  Viktor Reitenbach  Dieter Pudlo  Daniel Albrecht  Arron Tchouka Singhe  Kilian Nhungong Awemo  Joachim Wienand  Reinhard Gaupp 《Acta Geotechnica》2014,9(1):39-47

The feasibility of CO₂ storage and enhanced gas recovery (EGR) effects in the mature Altmark natural gas field in Central Germany has been studied in this paper. The investigations were comprehensive and comprise the characterization of the litho- and diagenetic facies, mineral content, geochemical composition, the petrophysical properties of the reservoir rocks with respect to their potential reactivity to CO₂ as well as reservoir simulation studies to evaluate the CO₂ wellbore injectivity and displacement efficiency of the residual gas by the injected CO₂. The Rotliegend sediments of the Altmark pilot injection area exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. The reservoir rock reactivity to CO₂ has been studied in autoclave experiments and associated effects on two-phase transport properties have been examined by means of routine and special core analysis before and after the laboratory runs. Dissolution of calcite and anhydrite during the short-term treatments leading to the enhancements of permeability and porosity as well as stabilization of the water saturation relevant for CO₂ injection have been observed. Numerical simulation of the injection process and EGR effects in a sector of the Altmark field coupled with a wellbore model revealed the possibility of injecting the CO₂ gas at temperatures as low as 10 °C and pressures around 40 bar achieving effective inflow in the reservoir without phase transition in the wellbore. The small ratio of injected CO₂ volume versus reservoir volume indicated no significant EGR effects. However, the retention and storage capacity of CO₂ will be maximized. The migration/extension of CO₂ varies as a function of heterogeneity both in the layers and in the reservoir. The investigation of CO₂ extension and pressure propagation suggested no breakthrough of CO₂ at the prospective production well during the 3-year injection period studied.  相似文献   

Modeling the effects of completion techniques and formation heterogeneity on CO₂ sequestration in shallow and deep saline aquifers   总被引：1，自引：1，他引：0  

Fang Yang  Baojun Bai  Shari Dunn-Norman 《Environmental Earth Sciences》2011,64(3):841-849

This work studied the effect of completion techniques and reservoir heterogeneity on CO₂ storage and injectivity in saline aquifers using a compositional reservoir simulator, CMG-GEM. Two reservoir models were built based on the published data to represent a deep saline aquifer and a shallow aquifer. The effect of various completion conditions on CO₂ storage was then discussed, including partial perforation of the reservoir net pay (partial completion), well geometry, orientation, location, and length. The heterogeneity effect was addressed by considering three parameters: mean permeability, the vertical to horizontal permeability ratio, and permeability variation. Sensitivity analysis was carried out using iSIGHT software (design of experiments) to determine the dominant factors affecting CO₂ storage capacity and injectivity. Simulation results show that the most favorable option is the perforation of all layers with horizontal wells 250–300 m long set in the upper layers. Mean permeability has the most effect on CO₂ storage capacity and injectivity; k _v/k _h affects CO₂ injectivity storage capacity more than permeability variation, V _k. More CO₂ can be stored in the heterogeneous reservoirs with low mean permeability; however, high injectivity can be achieved in the uniform reservoirs with high mean permeability.  相似文献   

Estimate CO2 storage capacity of the Johansen formation: numerical investigations beyond the benchmarking exercise     

Lingli Wei  Fredrik Saaf 《Computational Geosciences》2009,13(4):451-467

In this paper, Shell’s in-house reservoir simulator MoReS is applied to a recently introduced CO₂ sequestration benchmark problem entitled “Estimation of the CO₂ Storage Capacity of a Geological Formation” (Class et al. 2008). The principal objective of this benchmark is the simulation of CO₂ distribution within a modeling region, and leakage of CO₂ outside of it, for a period of 50 years. This study goes beyond the benchmarking exercise to investigate additional factors with direct relevance to CO₂ storage capacity estimations: water and gas relative permeabilities, permeability anisotropy, presence of sub-seismic features (conductive fractures, thin shale layers), regional hydrodynamic gradient, CO₂-enriched brine convection (due to brine density differences), and injection rates. The effects of hydrodynamic gradients and gravitationally induced convection only become significant over 100 s of years. This study has thus extended simulation time to 1,000 years. It is shown that grid resolution significantly impacts results. Vertical-grid refinement results in larger and thinner CO₂ plumes. Lateral-grid refinement delays leakage out of the model domain and reduces injection pressure for a given injection rate. Sub-seismic geological features such as fractures/faults and shale layers are demonstrated to have impact on CO₂ sequestration. Fractures located up-dip from the injector may lead to more leakage while the opposite may happen in the presence of fractures perpendicular to the dip. Thin shale layers produce stacked CO₂ blankets. They should be explicitly represented instead of being upscaled using a reduced vertical to horizontal permeability ratio. Results are seen to be far more sensitive to gas relative permeability and hysteresis than to variations in the water relative permeability models used. For a multi-injectors project, there is scope to optimize the phasing of injections to avoid potential fracturing near injectors.  相似文献   

Exhaustive brine production and complete CO2 storage in Jianghan Basin of China     

Qi Fang  Yilian Li 《Environmental Earth Sciences》2014,72(5):1541-1553

Pressure buildup limits CO₂ injectivity and storage capacity and pressure loss limits the brine production capacity and security, particularly for closed and semi-closed formations. In this study, we conduct a multiwell model to examine the potential advantages of combined exhaustive brine production and complete CO₂ storage in deep saline formations in the Jiangling Depression, Jianghan Basin of China. Simulation results show that the simultaneous brine extraction and CO₂ storage in saline formation not only effectively regulate near-wellbore and regional pressure of storage formation, but also can significantly enhance brine production capacity and CO₂ injectivity as well as storage capacity, thereby achieving maximum utilization of underground space. In addition, the combination of brine production and CO₂ injection can effectively mitigate the leakage risk between the geological units. With regard to the scheme of brine production and CO₂ injection, constant pressure injection is much superior to constant rate injection thanks to the mutual enhancement effect. The simultaneous brine production of nine wells and CO₂ injection of four wells under the constant pressure injection scheme act best in all respects of pressure regulation, brine production efficiency, CO₂ injectivity and storage capacity as well as leakage risk mitigation. Several ways to further optimize the combined strategy are investigated and the results show that increasing the injection pressure and adopting fully penetrating production wells can further significantly enhance the combined efficiency; however, there is no obvious promoting effect by shortening the well spacing and changing the well placement.  相似文献   

Investigation of geomechanical responses of reservoirs induced by carbon dioxide storage     

Kenneth Eshiet  Yong Sheng 《Environmental Earth Sciences》2014,71(9):3999-4020

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A sensitivity analysis of factors affecting in geologic CO2 storage in the Ordos Basin and its contribution to carbon neutrality     

《China Geology》2022,5(3):359-371

To accelerate the achievement of China’s carbon neutrality goal and to study the factors affecting the geologic CO₂ storage in the Ordos Basin, China’s National Key R&D Programs propose to select the Chang 6 oil reservoir of the Yanchang Formation in the Ordos Basin as the target reservoir to conduct the geologic carbon capture and storage (CCS) of 100000 t per year. By applying the basic theories of disciplines such as seepage mechanics, multiphase fluid mechanics, and computational fluid mechanics and quantifying the amounts of CO₂ captured in gas and dissolved forms, this study investigated the effects of seven factors that influence the CO₂ storage capacity of reservoirs, namely reservoir porosity, horizontal permeability, temperature, formation stress, the ratio of vertical to horizontal permeability, capillary pressure, and residual gas saturation. The results show that the sensitivity of the factors affecting the gas capture capacity of CO₂ decreases in the order of formation stress, temperature, residual gas saturation, horizontal permeability, and porosity. Meanwhile, the sensitivity of the factors affecting the dissolution capture capacity of CO₂ decreases in the order of formation stress, residual gas saturation, temperature, horizontal permeability, and porosity. The sensitivity of the influencing factors can serve as the basis for carrying out a reasonable assessment of sites for future CO₂ storage areas and for optimizing the design of existing CO₂ storage areas. The sensitivity analysis of the influencing factors will provide basic data and technical support for implementing geologic CO₂ storage and will assist in improving geologic CO₂ storage technologies to achieve China’s carbon neutralization goal.©2022 China Geology Editorial Office.  相似文献   

Evolution of sealing efficiency for CO2 geological storage due to mineral alteration within a hydrogeologically heterogeneous caprock     

《Applied Geochemistry》2015

In CO₂ geological storage (CGS) context, the evolution of the caprock sealing capacity has received increasing attention, particularly on a geological time span (thousands of years). At this time scale, geochemical reactions may enhance or weaken the caprock quality. It is widely recognized that, for the reservoir, geological heterogeneities affect the concentration and spatial distribution of CO₂, and then affect the extent of gas–water–rock interactions, which in turn alters the hydrogeological properties of the reservoir. However, much less attention of these effects has been paid to the caprock. In this study, we presented and applied a novel approach to evaluate the effects of permeability and porosity heterogeneities on the alteration of minerals, the associated evolution of the caprock sealing efficiency and the containment of supercritical CO₂ (scCO₂) within the caprock. Even though this is a generic study, several conditions and parameters such as pressure, permeability, and mineral composition, were extracted from a caprock layer of the Shiqianfeng Formation in the Ordos Basin demonstration site in China. For the sake of simplification, a 2-dimensional model was designed to represent the caprock domain. We firstly generated an appropriate heterogeneous random field of permeability with the average permeability taken from the uppermost mudstone layer of the Shiqianfeng Formation, and then the heterogeneity in porosity was incorporated using a joint normal distribution method based on the available data. Homogeneous mineral compositions of the reservoir and caprock were used in all simulations. Simulations of three cases were performed, including a homogeneous case, a case with only permeability heterogeneity and a case with both permeability and porosity heterogeneities. The results demonstrate dramatic influences of permeability and porosity heterogeneities on the migration of scCO₂ within the caprock, the alteration of minerals, and therefore the evolution of the caprock sealing quality. Specific to the data used in this study, hydrogeological heterogeneities facilitated the overall penetration of scCO₂ within the caprock and promoted the alteration of minerals, thereby weakening the caprock sealing efficiency over the simulation time.  相似文献   

二氧化碳羽流地热系统的碳封存经济分析          下载免费PDF全文

付雷  马鑫  刁玉杰  郑博文  郑长远  刘廷  邵炜 《中国地质》2022,49(5):1374-1384

【研究目的】 二氧化碳羽流地热系统（CPGS）在取热的同时可实现CO₂地质封存，在碳达峰与碳中和背景下，CPGS碳封存的经济性是众多学者关注的要点。【研究方法】 以松辽盆地泉头组为例，采用数值模拟方法对比分析了注入压力、井间距与回注温度对热提取率的影响，在供暖情景下，计算了CPGS供暖效益与碳封存成本，并与常规水热型地热系统供暖效益进行了对比。【研究结果】 受携热介质转变与热突破影响，CPGS开采井温度呈现“降低-稳定-降低”的趋势，其中井间距对开采井温降影响显著，井间距越小开采井温降越明显；热提取率与回注压力呈现正相关性，与回注温度呈现负相关性，井间距对热提取率影响不显著；CPGS与常规水热型地热系统相比，采热量呈现“高-低-高”三个阶段，其中回注压力越小、回注温度与储层温度越接近，实现CPGS较水介质多采热能所需的时间越短。【结论】 仅考虑CO₂价格与取热效益，供暖收益抵消部分碳封存成本后，井间距对CO₂封存单位成本影响最为显著，井间距越小，CO₂封存单位成本降低越迅速，在注采井间距300 m条件下，持续开采30 a后CO₂封存单位成本可降至160元/t。  相似文献   

Numerical simulation of carbon dioxide injection for enhanced gas recovery (CO2-EGR) in Altmark natural gas field     

Yang Gou  Zhengmeng Hou  Hejuan Liu  Lei Zhou  Patrick Were 《Acta Geotechnica》2014,9(1):49-58

This paper studied the CO₂-EGR in Altmark natural gas field with numerical simulations. The hydro-mechanical coupled simulations were run using a linked simulator TOUGH2MP-FLAC3D. In order to consider the gas mixing process, EOS7C was implemented in TOUGH2MP. A multi-layered 3D model (4.4 km × 2 km × 1 km) which consists of the whole reservoir, caprock and base rock was generated based on a history-matched PETREL model, originally built by GDF SUEZ E&P Deutschland GmbH for Altmark natural gas field. The model is heterogeneous and discretized into 26,015 grid blocks. In the simulation, 100,000 t CO₂ was injected in the reservoir through well S13 within 2 years, while gas was produced from the well S14. Some sensitivity analyses were also carried out. Simulation results show that CO₂ tends to migrate toward the production well S14 along a NW–SE fault. It reached the observation wells S1 and S16 after 2 years, but no breakthrough occurred in the production well. After 2 years of CO₂ injection, the reservoir pressure increased by 2.5 bar, which is beneficial for gas recovery. The largest uplift (1 mm) occurred at the bottom of the caprock. The deformation was small (elastic) and caprock integrity was not affected. With the injection rate doubled the average pressure increased by 5.3 bar. Even then the CO₂ did not reach the production well S14 after 2 years of injection. It could be concluded that the previous flow field was established during the primary gas production history. This former flow field, including CO₂ injection/CH₄ production rate during CO₂-EGR and fault directions and intensity are the most important factors affecting the CO₂ transport.  相似文献   

Interpretation of carbon dioxide diffusion behavior in coals   总被引：3，自引：1，他引：3  

Nikolai Siemons  Karl-Heinz A.A. Wolf  Johannes Bruining 《International Journal of Coal Geology》2007,72(3-4):315-324

Storage of carbon dioxide in geological formations is for many countries one of the options to reduce greenhouse gas emissions and thus to satisfy the Kyoto agreements. The CO₂ storage in unminable coal seams has the advantage that it stores CO₂ emissions from industrial processes and can be used to enhance coalbed methane recovery (CO₂-ECBM). For this purpose, the storage capacity of coal is an important reservoir parameter. While the amount of CO₂ sorption data on various natural coals has increased in recent years, only few measurements have been performed to estimate the rate of CO₂ sorption under reservoir conditions. An understanding of gas transport is crucial for processes associated with CO₂ injection, storage and enhanced coalbed methane (ECBM) production.A volumetric experimental set-up has been used to determine the rate of sorption of carbon dioxide in coal particles at various pressures and various grain size fractions. The pressure history during each pressure step was measured. The measurements are interpreted in terms of temperature relaxation and transport/sorption processes within the coal particles. The characteristic times of sorption increase with increasing pressure. No clear dependence of the characteristic time with respect to the particle size was found. At low pressures (below 1 MPa) fast gas diffusion is the prevailing mechanism for sorption, whereas at higher pressures, the slow diffusion process controls the gas uptake by the coal.  相似文献   

Method for the determination of residual carbon dioxide saturation using reactive ester tracers     

Matthew Myers  Linda Stalker  Andrew Ross  Christopher Dyt  Koon-Bay Ho 《Applied Geochemistry》2012

The mechanisms for storage of CO₂ in rock formations include structural/stratigraphic, mineral, solubility and residual trapping. Residual trapping is very important in terms of both containment security and storage capacity. However, to date, the contribution from residual trapping (i.e. immobilisation of supercritical fluid via capillarity in pore spaces) is still relatively difficult to quantify accurately. Using a laboratory-based testing program, this study demonstrates the feasibility of using reactive ester tracers (i.e. triacetin, propylene glycol diacetate and tripropionin), which partition between a mobile water phase and a stationary supercritical CO₂ phase, to quantify the residual CO₂ saturation, S_gr, of a rock formation. The proposed single-well test involves injecting these tracers into the subsurface, followed by CO₂ saturated water, where the ester tracers slowly hydrolyse to form products with differing partition coefficients. After a suitable period of time, allowing for partial hydrolysis, water containing the tracer mixture is produced from the subsurface and analysed using gas chromatography mass spectrometry (GCMS). A numerical simulator of the tracer behaviour in a reservoir is used to explain the differential breakthrough of these tracer compounds during water production to estimate S_gr. Computer modelling suggests that the use of esters tracers to determine CO₂ residual saturation is a potentially robust method. The supercritical CO₂/water partition coefficients directly dictate the amount of time that each tracer spends in the CO₂ and water phases. As such for modelling of tracer behaviour and estimating S_gr, knowing the tracer partition coefficient is essential; in this paper, the first laboratory study to determine the partition coefficients of these reactive ester tracers is described.  相似文献   

Preliminary reservoir model of enhanced coalbed methane (ECBM) in a subbituminous coal seam,Huntly Coalfield,New Zealand     

Sadiq J. Zarrouk  Tim A. Moore 《International Journal of Coal Geology》2009,77(1-2):153-161

The Huntly coalfield has significant coal deposits that contain biogenically-sourced methane. The coals are subbituminous in rank and Eocene in age and have been previously characterised with relatively low to moderate measured gas (CH₄) contents (2–4 m³/ton). The CO₂ holding capacity is relatively high (18.0 m³/ton) compared with that of CH₄ (2.6 m³/ton) and N₂ (0.7 m³/ton) at the same pressure (4 MPa; all as received basis). The geothermal gradient is also quite high at 55 °C/km.A study has been conducted which simulates enhancement of methane recovery (ECBM) from these deposits using a new version of the TOUGH2 (version 2) reservoir simulator (ECBM-TOUGH2) that can handle non-isothermal, multi-phase flows of mixtures of water, CH₄, CO₂ and N₂. The initial phase of the simulation is CH₄ production for the first 5 years of the field history. The model indicates that methane production can be significantly improved (from less than 80% recovery to nearly 90%) through injection of CO₂. However, although an increase in the rate of CO₂ injection increases the amount of CO₂ sequestered, the methane recovery (because of earlier breakthrough with increasing injection rate) decreases. Modeling of pure N₂ injection produced little enhanced CH₄ production. The injection of a hypothetical flue gas mixture (CO₂ and N₂) also produced little increase in CH₄ production. This is related to the low adsorption capacity of the Huntly coal to N₂ which results in almost instantaneous breakthrough into the production well.  相似文献   

Simulation study of CO2 sequestration potential of the Mary Lee coal zone, Black Warrior basin     

Ashkan Bahrami  Mohammad Jamialahmadi  Jamshid Moghadasi  Naimeh Alimohammadi 《Environmental Earth Sciences》2013,70(6):2501-2509

Significant potential exists for CO₂ sequestration in coalbed methane reservoirs of the Black Warrior basin. Reservoir simulation is an appropriate approach to estimate both the storage capacity and methane recovery enhancement. However, prior to a reliable reservoir modeling and simulation, conducting an accurate and comprehensive reservoir characterization study is necessary. The purpose of the present study is twofold: (a) to provide a rigorous reservoir characterization study required for modeling Mary Lee coal group in the Blue Creek field of the Black Warrior basin; (b) to run fluid flow simulations to predict the performance of ECBM process applied to an under pressured zone of the Mary Lee coal group. According to the current well configuration of Blue Creek field, three applicable well patterns, namely a direct line drive, an inverted 5-spot and a normal 5-spot were separately (i.e., in three distinct cases) used for simulating ECBM. Simulations were run on an approximately 32 ha (80-acre) drainage area, and included coal matrix shrinkage/swelling effects. The injected gas was assumed to be pure CO₂. Using an inverted 5-spot pattern, simulations predicted that after 7.5 years of CO₂ injection, approximately 32,000 tonnes of CO₂ would be sequestered per 32 ha of this zone and that methane recovery would be enhanced by 36 %. Using a normal 5-spot pattern, CO₂ breakthrough would occur 2.4 years earlier, and about 40,000 tonnes CO₂ would be sequestered. However, methane production would be enhanced by 33 %. Considering methane recovery enhancement, direct line drive pattern delivered poor results in comparison with two other patterns. As expected, the results also showed that CO₂ injection would increase water production.  相似文献   

Potential assessment of CO₂ geological storage based on injection scenario simulation: A case study in eastern Junggar Basin          下载免费PDF全文

Ma Xin  Wen Dong-guang  Yang Guo-dong  Li Xu-feng  Diao Yu-jie  Dong Hai-hai  Cao Wei  Yin Shu-guo  Zhang Yan-mei 《地下水科学与工程》2021,9(4):279-291

Carbon Capture and Storage (CCS) is one of the effective means to deal with global warming, and saline aquifer storage is considered to be the most promising storage method. Junggar Basin, located in the northern part of Xinjiang and with a large distribution area of saline aquifer, is an effective carbon storage site. Based on well logging data and 2D seismic data, a 3D heterogeneous geological model of the Cretaceous Donggou Formation reservoir near D7 well was constructed, and dynamic simulations under two scenarios of single-well injection and multi-well injection were carried out to explore the storage potential and CO₂ storage mechanism of deep saline aquifer with real geological conditions in this study. The results show that within 100 km² of the saline aquifer of Donggou Formation in the vicinity of D7 well, the theoretical static CO₂ storage is 71.967 × 10⁶ tons (P50)^①, and the maximum dynamic CO₂ storage is 145.295 × 10⁶ tons (Case2). The heterogeneity of saline aquifer has a great influence on the spatial distribution of CO₂ in the reservoir. The multi-well injection scenario is conducive to the efficient utilization of reservoir space and safer for storage. Based on the results from theoretical static calculation and the dynamic simulation, the effective coefficient of CO₂ storage in deep saline aquifer in the eastern part of Xinjiang is recommended to be 4.9%. This study can be applied to the engineering practice of CO₂ sequestration in the deep saline aquifer in Xinjiang.  相似文献   

Analytical and numerical investigation of multicomponent multiphase WAG displacements     

Tara LaForce  Kristian Jessen 《Computational Geosciences》2010,14(4):745-754

In this paper the ability of analytical solutions for four-component three-phase flow to predict displacement efficiency in water alternating gas (WAG) injection processes is studied. First analytical solutions for Riemann problems with injection compositions that are the average water and gas mixture for various WAG injection schemes are presented. These solutions are compared to numerical calculations with variable slug sizes and used to explore the effect of slug size, injecting water vs gas first, and the average injection composition on displacement efficiency in compositional WAG schemes. The example model is partially miscible WAG injection of water and CO₂ into an oil reservoir containing C₁₀ and CH₄ with and without a mobile aqueous phase present initially. The trailing end of the water and gas profiles are sensitive to whether water or gas is injected first, but the magnitude of the oil bank and the breakthrough time of the injected fluids are accurately predicted by the analytical solutions, even for displacements where large water and gas slugs are injected. Fluctuations in the saturation and composition profiles resulting from the alternating injection sequence in the WAG simulations appear as super-imposed on top of the sequence of rarefaction and shock waves predicted by analytical solutions. As the number of slugs increases, the effect of alternating boundary conditions diminishes and the displacements predicted by numerical calculations converge to the analytical solutions.  相似文献   

低渗透油藏二氧化碳混相驱注采方式研究——以克拉玛依油田X区克下组低渗透油藏为例          下载免费PDF全文

李玮  师庆三  董海海  侯锐 《中国地质》2022,49(2):485-495

[研究目的]克拉玛依油田X区克下组低渗透油藏存在物性差、水驱开发采收率低等问题,影响了油田的可持续发展.CO2是全球变暖的主要成分,世界各国都在想方设法减少CO2的排放量,本文试图利用CO2驱油气方式提高该油藏的采收率,变害为利.[研究方法]文章选取研究区60余口取心井目标层位岩心样品,开展扫描电镜及压汞测试分析等研究...  相似文献   

Geologic assessment and injection design for a pilot CO<Subscript>2</Subscript>-enhanced oil recovery and sequestration demonstration in a heterogeneous oil reservoir: Citronelle Field,Alabama, USA     

Richard A. Esposito  Jack C. Pashin  Denise J. Hills  Peter M. Walsh 《Environmental Earth Sciences》2010,60(2):431-444

CO₂ pilot injection studies, with site-specific geologic assessment and engineering reservoir design, can be instrumental for demonstrating both incremental enhanced oil recovery and permanent geologic storage of greenhouse gases. The purpose of this paper is to present the geologic and reservoir analyses in support of a field pilot test that will evaluate the technical and economic feasibility of commercial-scale CO₂-enhanced oil recovery to increase oil recovery and extend the productive life of the Citronelle Oil Field, the largest conventional oil field in Alabama (SE USA). Screening of reservoir depth, oil gravity, reservoir pressure, reservoir temperature, and oil composition indicates that the Cretaceous-age Donovan sand, which has produced more than 169 × 10⁶ bbl in Citronelle Oil Field, is amenable to miscible CO₂ flooding. The project team has selected an 81 ha (200 ac) 5-spot test site with one central gas injector, two producers, and two initially temporarily abandoned production wells that are now in production. Injection is planned in two separate phases, each consisting of 6,804 t (7,500 short tons) of food-grade CO₂. The Citronelle Unit B-19-10 #2 well (Permit No. 3232) is the CO₂ injector for the first injection test. The 14-1 and 16-2 sands of the upper Donovan are the target zones. These sandstone units consist of fine to medium-grained sandstone that is enveloped by variegated mudstone. Both of these sandstone units were selected based on the distribution of perforated zones in the test pattern, production history, and the ability to correlate individual sandstone units in geophysical well logs. The pilot injections will evaluate the applicability of tertiary oil recovery to Citronelle Field and will provide a large volume of information on the pressure response of the reservoirs, the mobility of fluids, time to breakthrough, and CO₂ sweep efficiency. The results of the pilot injections will aid in the formulation of commercial-scale reservoir management strategies that can be applied to Citronelle Field and other geologically heterogeneous oil fields and the design of similar pilot injection projects.  相似文献   

Improving the CO2 well injectivity and enhanced coalbed methane production performance in coal seams     

Sevket Durucan  Ji-Quan Shi 《International Journal of Coal Geology》2009,77(1-2):214-221

This paper reports on the performance comparison for different CO₂-ECBM schemes in relatively thin unminable seams typical of Northern Appalachian coal basin using a horizontal well configuration. Numerical simulations based upon public-domain coalbed reservoir properties indicated that injection of pure CO₂ is likely to result in only limited incremental methane recovery if any over primary recovery, due to the low injection rates that can be achieved. On the other hand, the presence of the nitrogen component in the injected gas stream is capable of improving the efficiency of enhanced methane recovery significantly without compromising the net CO₂ injection rates, as a result of improved injectivity over pure CO₂ injection. There is, however, a trade off between incremental methane recovery and produced gas purity due to early nitrogen breakthrough.  相似文献   

Geologic factors controlling CO₂ storage capacity and permanence: case studies based on experience with heterogeneity in oil and gas reservoirs applied to CO₂ storage     

W. A. Ambrose  S. Lakshminarasimhan  M. H. Holtz  V. Nú?ez-López  S. D. Hovorka  I. Duncan 《Environmental Geology》2008,54(8):1619-1633

A variety of structural and stratigraphic factors control geological heterogeneity, inferred to influence both sequestration capacity and effectiveness, as well as seal capacity. Structural heterogeneity factors include faults, folds, and fracture intensity. Stratigraphic heterogeneity is primarily controlled by the geometry of depositional facies and sandbody continuity, which controls permeability structure. The permeability structure, in turn, has implications for CO₂ injectivity and near-term migration pathways, whereas the long-term sequestration capacity can be inferred from the production history. Examples of Gulf Coast oil and gas reservoirs with differing styles of stratigraphic heterogeneity demonstrate the impact of facies variability on fluid flow and CO₂ sequestration potential. Beach and barrier-island deposits in West Ranch field in southeast Texas are homogeneous and continuous. In contrast, Seeligson and Stratton fields in south Texas, examples of major heterogeneity in fluvial systems, are composed of discontinuous, channel-fill sandstones confined to narrow, sinuous belts. These heterogeneous deposits contain limited compartments for potential CO₂ storage, although CO₂ sequestration effectiveness may be enhanced by the high number of intraformational shale beds. These field examples demonstrate that areas for CO₂ storage can be optimized by assessing sites for enhanced oil and gas recovery in mature hydrocarbon provinces.  相似文献   

Numerical simulation and optimization of CO2 sequestration in saline aquifers for vertical and horizontal well injection     

Zheming Zhang  Ramesh K. Agarwal 《Computational Geosciences》2012,16(4):891-899

With heightened concerns on CO₂ emissions from pulverized-coal (PC) power plants, there has been major emphasis in recent years on the development of safe and economical geological carbon sequestration (GCS) technology. Saline aquifers are considered very attractive for GCS because of their large storage capacity in U.S. and other parts of the world for long-term sequestration. However, uncertainties about storage efficiency as well as leakage risks remain major areas of concern that need to be addressed before the saline aquifers can be fully exploited for carbon sequestration. A genetic algorithm-based optimizer has been developed and coupled with the well-known multiphase numerical solver TOUGH2 to optimally examine various injection strategies for increasing the CO₂ storage efficiency as well as for reducing its plume migration. The optimal injection strategies for CO₂ injection employing a vertical injection well and a horizontal injection well are considered. To ensure the accuracy of the results, the combined hybrid numerical solver/optimizer code was validated by conducting simulations of three widely used benchmark problems employed by carbon sequestration researchers worldwide. The validated code is then employed to optimize the proposed water-alternating-gas injection scheme for CO₂ sequestration using both the vertical and the horizontal injection wells. The results suggest the potential benefits of CO₂ migration control and dissolution. The optimization capability of the hybrid code holds a great promise in studying a host of other problems in GCS, namely how to optimally enhance capillary trapping, accelerate the dissolution of CO₂ in water or brine, and immobilize the CO₂ plume.  相似文献