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1.
Enhanced oil recovery based on CO2 injection is expected to increase recovery from Croatian oil fields. Large quantities of CO2 are generated during hydrocarbon processing produced from gas and gas condensate fields situated in the north-western part of Croatia. First CO2 injection project will be implemented on the Ivani? Oil Field. Numerical modelling based on Upper Miocene sandstone core samples testing results have shown the decrease of oil viscosity during CO2 injection. Some of the characteristics of the testing samples are porosity 21.5–23.6 %, permeability 14–80 × 10?15 m2 and initial water saturation 28–38.5 %. Water alternating foam (WAF) and water alternating gas (WAG) simulations have provided satisfactory results. The WAF injection process has provided better results, but due to the process sensitivity and costs WAG is recommended for future application. During the pilot project 16 × 106 m3 CO2 and 5 × 104 m3 of water were injected. Additional amounts of hydrocarbons (4,440 m3 of oil and 2.26 × 106 m3 of gas) were produced which confirmed injection of CO2 as a successful tertiary oil recovery mechanism in Upper Miocene sandstone reservoirs in the Croatian part of the Pannonian Basin System.  相似文献   

2.
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   

3.
Carbon dioxide (CO2) emission from the river-type reservoir is an hotspot of carbon cycle within inland waters. However, related studies on the different types of reservoirs are still inadequate. Therefore, we sampled the Three Gorges Reservoir (TGR), a typical river-type reservoir having both river and lake characteristics, using an online system (HydroCTM/CO2) and YSI-6600v2 meter to determine the partial pressure of carbon dioxide (pCO2) and physical chemical parameters in 2013. The results showed that the CO2 flux from the mainstream ranged from 26.1 to 92.2 mg CO2/m2 h with average CO2 fluxes of 50.0 mg/m2 h. The CO2 fluxes from the tributary ranged from ?10.91 to 53.95 mg CO2/m2 h with area-weighted average CO2 fluxes of 11.4 mg/m2 h. The main stream emits CO2 to the atmosphere the whole year; however, the surface water of the tributary can sometimes act as a sink of CO2 for the atmosphere. As the operation of the TGR, the tributary became more favorable to photosynthetic uptake of CO2 especially in summer. The total CO2 flux was estimated to be 0.34 and 0.03 Tg CO2/year from the mainstream and the tributaries, respectively. Our emission rates are lower than previous estimates, but they are in agreement with the average CO2 flux from temperate reservoirs estimated by Barros et al. (Nat Geosci 4(9):593–596, 2011).  相似文献   

4.
The present paper provides a case study of the assessment of the potential for CO2 storage in the deep saline aquifers of the Bécancour region in southern Québec. This assessment was based on a hydrogeological and petrophysical characterization using existing and newly acquired core and well log data from hydrocarbon exploration wells. Analyses of data obtained from different sources provide a good understanding of the reservoir hydrogeology and petrophysics. Profiles of formation pressure, temperature, density, viscosity, porosity, permeability, and net pay were established for Lower Paleozoic sedimentary aquifers. Lateral hydraulic continuity is dominant at the regional scale, whereas vertical discontinuities are apparent for most physical and chemical properties. The Covey Hill sandstone appears as the most suitable saline aquifer for CO2 injection/storage. This unit is found at a depth of more than 1 km and has the following properties: fluid pressures exceed 14 MPa, temperature is above 35 °C, salinity is about 108,500 mg/l, matrix permeability is in the order of 3 × 10?16 m2 (0.3 mDarcy) with expected higher values of formation-scale permeability due to the presence of natural fractures, mean porosity is 6 %, net pay reaches 282 m, available pore volume per surface area is 17 m3/m2, rock compressibility is 2 × 10?9 Pa?1 and capillary displacement pressure of brine by CO2 is about 0.4 MPa. While the containment for CO2 storage in the Bécancour saline aquifers can be ensured by appropriate reservoir characteristics, the injectivity of CO2 and the storage capacity could be limiting factors due to the overall low permeability of aquifers. This characterization offers a solid basis for the subsequent development of a numerical hydrogeological model, which will be used for CO2 injection capacity estimation, CO2 injection scenarios and risk assessment.  相似文献   

5.
《International Geology Review》2012,54(14):1792-1812
Abundant crude oil and CO2 gas coexist in the fourth member of the Upper Cretaceous Quantou reservoir in the Huazijing Step of the southern Songliao Basin, China. Here, we present results of a petrographic characterization of this reservoir based on polarizing microscope, X-ray diffraction, fluid inclusion, and carbon–oxygen isotopic data. These data were used to identify whether CO2 might be trapped in minerals after the termination of a CO2-enhanced oil recovery (EOR) project, and to determine what effects might the presence of CO2 have on the properties of crude oil in the reservoir. The crude oil reservoir in the study area, which coexists with mantle-derived CO2, is hosted by dawsonite-bearing lithic arkoses and feldspathic litharenites. These sediments are characterized by a paragenetic sequence of clay, quartz overgrowth, first-generation calcite, dawsonite, second-generation calcite, and ankerite. The dawsonite analysed during this study exhibits δ13 C (Peedee Belemnite, PDB) values of ?4.97‰ to 0.67‰, which is indicative for the formation of magmatic–mantle CO2. The paragenesis and compositions of fluid inclusions in the dawsonite-bearing sandstones record a sequence of two separate filling events, the first involving crude oil and the second involving magmatic–mantle CO2. The presence of prolate primary hydrocarbon inclusions within the dawsonite indicates that these minerals precipitated from oil-bearing pore fluids at temperatures of 94–97°C, in turn suggesting that CO2 could be stored as carbonate minerals after the termination of a CO2-EOR project. In addition, the crude oil in the basin would become less dense after deposition of bitumen by deasphalting the injection of CO2 gas into the oil pool.  相似文献   

6.
H2S and CO2 are found in elevated concentrations in the reservoirs near the Carboniferous–Ordovician unconformity in the Hetianhe Field of the Tarim Basin, NW China. Chemical and isotopic analyses have been performed on produced gases, formation waters and reservoir rocks to determine the origin of CO2 and H2S and to explain the heterogeneous distribution of isotopic and geochemical characteristics of petroleum fluids. It is unlikely that H2S and CO2 had a mantle component since associated helium has an isotope ratio totally uncharacteristic of this source. Instead, H2S and CO2 are probably the result of sulphate reduction of the light hydrocarbon gases (LHG). Increasing H2S concentrations and CO2/(CO2+ΣC1–4) values to the west of the Hetianhe Field occur commensurately with increasingly heavy hydrocarbon gas δ13C values. However, thermochemical sulphate reduction is unlikely because the temperatures of the reservoirs are too low, no H2S or rare pyrite was detected in deeper reservoirs (where more TSR should have occurred) and inferred δ34S values of H2S (from late-stage pyrite in the Carboniferous and Ordovician reservoirs) are as low as −24.9‰. Such low δ34S values discount the decomposition of organic matter as a major source of H2S and CO2. Bacterial sulphate reduction of the light hydrocarbon gases in the reservoir, possibly coupled indirectly with the consumption of organic acids and anions is most likely. The result is the preferential oxidation of 12C-rich alkanes (due to the kinetic isotope effect) and decreasing concentration of organic acids and anions. Modern formation water stable isotope data reveal that it is possible that sulphate-reducing bacteria were introduced into the reservoir by an influx of meteoric water from the west by way of an inversion-related unconformity. This may account for the apparently stronger influence of bacterial sulphate reduction to the west of the Hetianhe Field, and the consequent greatest decrease of the δ13C-CO2 values and the greatest increase in δ13C values of the alkane gases.  相似文献   

7.
Carbon dioxide (CO2) sequestration in depleted sandstone hydrocarbon reservoirs could be complicated by a number of geomechanical problems associated with well drilling, completions, and CO2 injection. The initial production of hydrocarbons (gas or oil) and the resulting pressure depletion as well as associated reduction in horizontal stresses (e.g., fracture gradient) narrow the operational drilling mud weight window, which could exacerbate wellbore instabilities while infill drilling. Well completions (casing, liners, etc.) may experience solids flowback to the injector wells when injection is interrupted due to CO2 supply or during required system maintenance. CO2 injection alters the pressure and temperature in the near wellbore region, which could cause fault reactivation or thermal fracturing. In addition, the injection pressure may exceed the maximum sustainable storage pressure, and cause fracturing and fault reactivation within the reservoirs or bounding formations. A systematic approach has been developed for geomechanical assessments for CO2 storage in depleted reservoirs. The approach requires a robust field geomechanical model with its components derived from drilling and production data as well as from wireline logs of historical wells. This approach is described in detail in this paper together with a recent study on a depleted gas field in the North Sea considered for CO2 sequestration. The particular case study shows that there is a limitation on maximum allowable well inclinations, 45° if aligning with the maximum horizontal stress direction and 65° if aligning with the minimum horizontal stress direction, beyond which wellbore failure would become critical while drilling. Evaluation of sanding risks indicates no sand control installations would be needed for injector wells. Fracturing and faulting assessments confirm that the fracturing pressure of caprock is significantly higher than the planned CO2 injection and storage pressures for an ideal case, in which the total field horizontal stresses increase with the reservoir re-pressurization in a manner opposite to their reduction with the reservoir depletion. However, as the most pessimistic case of assuming the total horizontal stresses staying the same over the CO2 injection, faulting could be reactivated on a fault with the least favorable geometry once the reservoir pressure reaches approximately 7.7 MPa. In addition, the initial CO2 injection could lead to a high risk that a fault with a cohesion of less than 5.1 MPa could be activated due to the significant effect of reduced temperature on the field stresses around the injection site.  相似文献   

8.
Mechanical damage (e.g. faults and fractures) related to tectonic forces and/or variations in formation pore pressures may enable the leakage of fluids through otherwise effective seal rocks. Characterisation of faults and fractures within seals is therefore essential for the assessment of long-term trap integrity in potential CO2 storage sites. 3D seismic reflection data are used to describe a previously unrecognised network of extensive, small Miocene-age faults with displacement of generally <30 m and lengths that vary between ～300 and 2500 m above the Snapper Field, in the Gippsland Basin. The Snapper Field is a nearly depleted oil and gas field that presents an attractive site for potential CO2 storage due its structural closure and because it has effectively retained significant natural hydrocarbon (including CO2) columns over geological time-scales. Volume-based seismic attributes reveal that this fault system is located within the Oligocene Lakes Entrance Formation of the Seaspray Group, which acts as the regional seal to the Latrobe Group reservoirs in the Gippsland Basin. Detailed analysis of fault lengths and linkages suggests that the Miocene faults are non-tectonic, polygonal faults, although the displacement analysis of fault segments reveals strong correlations with the both the structure of the underlying Top Latrobe surface and normal faults that segment the Latrobe Group reservoirs, suggesting that the development of this fault system has been influenced by underlying structures. The geological evidence for long-term retention of hydrocarbons within the Snapper Field suggests that this fault system has not compromised the integrity of the Lakes Entrance Formation seal, although elevated pore pressures during CO2 injection could potentially lead to reactivation of these structures.  相似文献   

9.
Fixed-ammonium in clays associated with crude oils   总被引：3，自引：0，他引：3  
The association of ammonium (NH4+) silicates with organic-rich sedimentary environments has stimulated interest in the chemical cycle of N, and its possible application as an indicator of in situ organic maturation reactions or crude oil migration. Fixed-NH4 in clay minerals was determined from three hydrocarbon occurrences of similar depositional environment but different ages, depth and thermal maturity, to determine whether anomalously high NH4-substitution occurs near mature hydrocarbons. Results show higher fixed-NH4 concentrations in marginally mature mudstones than in immature sediments. The highest fixed-NH4 concentrations were found in clays from sandstone reservoirs containing migrated crude oil.Fixed-NH4 in clays from Holocene oil seep sediments in the Gulf of Mexico continental slope, offshore Louisiana, averages 0.08 wt % and increases with depth in shallow cores (420 cm), reflecting an early diagenetic trend that is apparently not influenced by migrating crude oil. Programmed pyrolysis shows that the sediments are thermally immature (av.Tmax = 419°C). High Hydrogen Index values (av.= 359mg/g) are the result of biodegraded crude oil, and a high Oxygen Index (av.= 182mg/g) reflects the presence of authigenic carbonate.Fixed-NH4 averages 0.16 wt % in Wilcox Group (Eocene) mudstones enclosing two sandstone reservoirs at Fordoche Field, onshore Louisiana. In comparison to these mudstones, anomalously high NH4-fixation appears to occur in reservoir clay minerals. Pyrolysis shows that the sediments are marginally mature for crude oil generation (av.Tmax = 432°C). Average Hydrogen Index (187 mg/g) and Oxygen Index values (75 mg/g) are consistent with oil-prone Type II and Type III kerogen. Increased pyrolysis Production Index values and solvent extraction shows the presence of migrated crude oil. This suggests that a reaction which releases NH3 during crude oil generation or migration is recorded byNH4+ substitution in clays.Fixed-NH4 and total organic carbon (TOC) at Fordoche Field show no statistically significant correlation, suggesting that NH4+ substitution in clay minerals is not simply related to the amount of organic matter in the section, but is also influenced by the presence of crude oil. Once NH4+ has been fixed in clays, it is a more stable hydrocarbon proximity indicator than pore fluid tracers, because it is less influenced by later chemical or geological changes.  相似文献   

10.
综合钻井、大量实测剖面、样品测试分析和区域地质资料，对西昌盆地白果湾组烃源岩生烃强度、镜质体反射率、砂岩储层物性等关键指标进行了系统评价。西昌盆地上三叠统白果湾组主要油气储层类型为中-粗砂岩，有利层段主要发育在白果湾组一段、三段和四段，砂岩具有中孔低渗、区域分布广、厚度大等特征，ZD-1井揭示砂岩含油气性好。西昌盆地白果湾组烃源岩在盆地中心厚度大，盆地中心的生烃强度达（56.74~97.70）×108 m3/km2。烃源岩成熟度（RO）在1.08%~3.98%范围，具有东低西高的特征。通过综合分析西昌盆地油气形成的关键指标，优选了夹铁-四开致密砂岩油气成藏有利区和4个甜点区，该区生烃强度（10~80）×108m3/km2，RO为1.08%~3.0%，中-粗砂岩厚度为10~50m，天然气资源量为6756×108m3，可形成"改造再重建"致密砂岩油气藏。  相似文献   

11.
Deep fluids in a petroliferous basin generally come from the deep crust or mantle beneath the basin basement, and they transport deep substances(gases and aqueous solutions) as well as heat to sedimentary strata through deep faults. These deep fluids not only lead to large-scale accumulations of CO_2, CH_4, H_2, He and other gases, but also significantly impact hydrocarbon generation and accumulation through organic-inorganic interactions. With the development of deep faults and magmatic-volcanic activities in different periods, most Chinese petroliferous basins have experienced strong impacts associated with deep fluid activity. In the Songliao, Bohai Bay, Northern Jiangsu, Sanshui, Yinggehai and Pearl Mouth Basins in China, a series of CO_2 reservoirs have been discovered. The CO_2 content is up to 99%, with δ~(13)C_(CO2) values ranging from-4.1‰ to-0.37‰ and ~3He/~4He ratios of up to 5.5 Ra. The abiogenic hydrocarbon gas reservoirs with commercial reserves, such as the Changde, Wanjinta, Zhaozhou, and Chaoyanggou reservoirs, are mainly distributed in the Xujiaweizi faulted depression of the Songliao Basin. The δ~(13)CCH4 values of the abiogenic alkane gases are generally -30‰ and exhibit an inverse carbon isotope sequence of δ~(13)C_(CH4)δ~(13)C_(C2H6)δ~(13)C_(C3H8)δ~(13)C_(C4H10). According to laboratory experiments, introducing external H_2 can improve the rate of hydrocarbon generation by up to 147% through the kerogen hydrogenation process. During the migration from deep to shallow depth, CO_2 can significantly alter reservoir rocks. In clastic reservoirs, feldspar is easily altered by CO_2-rich fluids, leading to the formation of dawsonite, a typical mineral in high CO_2 partial pressure environments, as well as the creation of secondary porosity. In carbonate reservoirs, CO_2-rich fluids predominately cause dissolution or precipitation of carbonate minerals. The minerals, e.g., calcite and dolomite, show some typical features, such as higher homogenization temperatures than the burial temperature, relatively high concentrations of Fe and Mn, positive Eu anomalies, depletion of 18 O and enrichment of radiogenic ~(87)Sr. Due to CO_2-rich fluids, the development of high-quality carbonate reservoirs is extended to deep strata. For example, the Well TS1 in the northern Tarim Basin revealed a high-quality Cambrian dolomite reservoir with a porosity of 9.1% at 8408 m, and the Well ZS1 C in the central Tarim Basin revealed a large petroleum reserve in a Cambrian dolomite reservoir at ~6900 m. During the upward migration from deep to shallow basin strata, large volumes of supercritical CO_2 may extract petroleum components from hydrocarbon source rocks or deep reservoirs and facilitate their migration to shallow reservoirs, where the petroleum accumulates with the CO_2. Many reservoirs containing both supercritical CO_2 and petroleum have been discovered in the Songliao, Bohaiwan, Northern Jiangsu, Pearl River Mouth and Yinggehai Basins. The components of the petroleum trapped with CO_2 are dominated by low molecular weight saturated hydrocarbons.  相似文献   

12.
Frontier exploration in the Kuqa Depression, western China, has identified the continuous tight-sand gas accumulation in the Lower Cretaceous and Lower Jurassic as a major unconventional gas pool. However, assessment of the shale gas resource in the Kuqa Depression is new. The shale succession in the Middle–Upper Triassic comprises the Taliqike Formation (T3t), the Huangshanjie Formation (T3h) and the middle–upper Karamay Formation (T2–3k), with an average accumulated thickness of 260 m. The high-quality shale is dominated by type III kerogen with high maturity and an average original total organic carbon (TOC) of about 2.68 wt%. An improved hydrocarbon generation and expulsion model was applied to this self-contained source–reservoir system to reveal the gas generation and expulsion (intensity, efficiency and volume) characteristics of Middle–Upper Triassic source rocks. The maximum volume of shale gas in the source rocks was obtained by determining the difference between generation and expulsion volumes. The results indicate that source rocks reached the hydrocarbon expulsion threshold of 1.1% VR and the hydrocarbon generation and expulsion reached their peak at 1.0% VR and 1.28% VR, with the maximum rate of 56 mg HC/0.1% TOC and 62.8 mg HC/0.1% TOC, respectively. The volumes of gas generation and expulsion from Middle–Upper Triassic source rocks were 12.02 × 1012 m3 and 5.98 × 1012 m3, respectively, with the residual volume of 6.04 × 1012 m3, giving an average gas expulsion efficiency of 44.38% and retention efficiency of 55.62%. Based on the gas generation and expulsion characteristics, the predicted shale gas potential volume is 6.04 × 1012 m3, indicating a significant shale gas resource in the Middle–Upper Triassic in the eastern Kuqa Depression.  相似文献   

13.
Basalts interbedded with oil source rocks are discovered frequently in rift basins of eastern China, where CO2 is found in reservoirs around or within basalts, for example in the Binnan reservoir of the Dongying Depression. In the reservoirs, CO2 with heavy carbon isotopic composition (δ13C>-10‰ PDB) is in most cases accounts for 40% of the total gas reserve, and is believed to have resulted from degassing of basaltic magma from the mantle. In their investigations of the Binnan reservoir, the authors suggested that the CO2 would result from interactions between the source rocks and basalts. As the source rocks around basalts are rich in carbonate minerals, volcanic minerals, transition metals and organic matter, during their burial history some of the transition metals were catalyzed on the thermal degradation of organic matter into hydrocarbons and on the decomposition of carbonate minerals into CO2, which was reproduced in thermal simulations of the source rocks with the transition metals (Ni and Co). This kind of CO2 accounts for 55%-85% of the total gas reserve generated in the process of thermal simulation, and its δ13C values range from -11‰- -7.2‰ PDB, which are very similar to those of CO2 found in the Binnan reservoir. The co-generation of CO2 and hydrocarbon gases makes it possible their accumulation together in one trap. In other words, if the CO2 resulted directly from degassing of basaltic magma or was derived from the mantle, it could not be accumulated with hydrocarbon gases because it came into the basin much earlier than hydrocarbon generation and much earlier than trap formation. Therefore, the source rocks around basalts generated hydrocarbons and CO2 simultaneously through catalysis of Co and Ni transition metals, which is useful for the explanation of co-accumulation of hydrocarbon gases and CO2 in rift basins in eastern China.  相似文献   

14.
The Wujiang River is an important tributary to the Changjiang River that has been intensively impounded for hydropower exploitation. To understand the potential impact of reservoir construction on the riverine inorganic carbon transport, seasonal longitudinal sampling was conducted in four reservoirs Hongjiadu (HJD), Dongfeng (DF), Suofengying (SFY) and Wujiangdu (WJD) along the Wujiang River from April 2006 to January 2007. Results indicated that damming the river induced an obvious discontinuity of water chemistry in the warmer seasons. δ 13C of dissolved inorganic carbon (DIC) ranged from ?3 to ?11.4 ‰, likely as the results of photosynthesis, respiration and carbonate weathering. During periods of thermal stratification, the addition of CO2 from respiration to hypolimnion and the deep water release for hydropower generation led to higher pCO2 downstream, as well as 13C depletion in DIC and undersaturated to calcite. An estimate of DIC budget indicated that only DF reservoir was the sink for DIC while reservoirs HJD, SFY and WJD were the sources for DIC. However, when the retained water was taken into account, for the reason of water storage occurring mainly in HJD and DF, all reservoirs became the sources for DIC with exporting rates of 26.68, 7.97, 6.22 and 11.80 % for HJD, DF, SFY and WJD, respectively.  相似文献   

15.
《Applied Geochemistry》1993,8(3):285-295
Geochemical modelling of fluid-rock interaction is one theoretical approach that can be used for understanding diagenetic processes and their effects on reservoir quality. Results of successive modelling of dissolution and heating, using two specific path calculation codes DISSOL and THERMAL, from 25 to 160°C, are presented. If one considers one volume of reacting solution, the diagenetic effects are very important for fluid chemistry, while mass transfers have little effect on porosity. Only cumulative effects due to the circulation of fluids in reservoirs may explain the extent of diagenetic processes on minerals. Comparison between the computed data (this study) and available data from the North Sea, from Gulf Coast sandstones, from Pattani Basin (Gulf of Thailand), from San Joaquin Basin (California, U.S.A.) and from a Triassic sandstone reservoir in the Rhine Graben (Cronenbourg, France) show interesting similarities in the chemical evolution of the fluid. The modelling has interesting implications for the relations between ph-pCO2 conditions and the diagenetic stability of calcic plagioclase.  相似文献   

16.
The spatial and temporal variations of the flux of CO2 were determined during 2007 in the Recife estuarine system (RES), a tropical estuary that receives anthropogenic loads from one of the most populated and industrialized areas of the Brazilian coast. The RES acts as a source of nutrients (N and P) for coastal waters. The calculated CO2 fluxes indicate that the upstream inputs of CO2 from the rivers are largely responsible for the net annual CO2 emission to the atmosphere of +30 to +48 mmol m?2 day?1, depending on the CO2 exchange calculation used, which mainly occurs during the late austral winter and early summer. The observed inverse relationship between the CO2 flux and the net ecosystem production (NEP) indicates the high heterotrophy of the system (except for the months of November and December). The NEP varies between ?33 mmol m?2 day?1 in summer and ?246 mmol m?2 day?1 in winter. The pCO2 values were permanently high during the study period (average ~4,700 μatm) showing a gradient between the inner (12,900 μatm) and lower (389 μatm) sections on a path of approximately 30 km. This reflects a state of permanent pollution in the basin due to the upstream loading of untreated domestic effluents (N/P?=?1,367:6 μmol kg?1 and pH?=?6.9 in the inner section), resulting in the continuous mineralization of organic material by heterotrophic organisms and thereby increasing the dissolved CO2 in estuarine waters.  相似文献   

17.
Aquatic ecosystems have been identified as a globally significant source of nitrous oxide (N2O) due to continuous active nitrogen involvement, but the processes and influencing factors that control N2O production are still poorly understood, especially in reservoirs. For that, monthly N2O variations were monitored in Dongfeng reservoir (DFR) with a mesotrophic condition. The dissolved N2O concentration in DFR displayed a distinct spatial–temporal pattern but lower than that in the eutrophic reservoirs. During the whole sampling year, N2O saturation ranging from 144% to 640%, indicating that reservoir acted as source of atmospheric N2O. N2O production is induced by the introduction of nitrogen (NO3 ?, NH4 +) in mesotrophic reservoirs, and is also affected by oxygen level and water temperature. Nitrification was the predominate process for N2O production in DFR due to well-oxygenated longitudinal water layers. Mean values of estimated N2O flux from the air–water interface averaged 0.19 µmol m?2 h?1 with a range of 0.01–0.61 µmol m?2 h?1. DFR exhibited less N2O emission flux than that reported in a nearby eutrophic reservoir, but still acted as a moderate N2O source compared with other reservoirs and lakes worldwide. Annual emissions from the water–air interface of DFR were estimated to be 0.32 × 105 mol N–N2O, while N2O degassing from releasing water behind the dam during power generation was nearly five times greater. Hence, N2O degassing behind the dam should be taken into account for estimation of N2O emissions from artificial reservoirs, an omission that historically has probably resulted in underestimates. IPCC methodology should consider more specifically N2O emission estimation in aquatic ecosystems, especially in reservoirs, the default EF5 model will lead to an overestimation.  相似文献   

18.
To evaluate mineralogical-geochemical changes within the reservoir of the Ketzin pilot CO2 storage site in Brandenburg, Germany, two sets of laboratory experiments on sandstone and siltstone samples from the Stuttgart Formation have been performed. Samples were exposed to synthetic brine and pure CO2 at experimental conditions and run durations of 5.5 MPa/40 °C/40 months for sandstone and 7.5 MPa/40 °C/6 months for siltstone samples, respectively. Mineralogical changes in both sets of experiments are generally minor making it difficult to differentiate natural variability of the whole rock samples from CO2-induced alterations. Results of sandstone experiments suggest dissolution of the anorthite component of plagioclase, anhydrite, K-feldspar, analcime, hematite and chlorite + biotite. Dissolution of the anorthite component of plagioclase, anhydrite and K-feldspars is also observed in siltstone experiments. In an inverse modeling approach, an extensive set of equilibrium simulations was set up in order to reproduce the experimental observations of the sandstone experiments. Simulations generally show fairly good matches with the experimental observations. Best matches with measured brine data are obtained from mineral combinations of albite, analcime, anhydrite, dolomite, hematite, illite, and kaolinite. The major discrepancies during equilibrium modeling, however, are reactions involving Fe2+ and Al3+. The best matching subsets of the equilibrium models were finally run including kinetic rate laws. These simulations reveal that experimentally determined brine data was well matched, but reactions involving K+ and Fe2+ are not fully covered. The modeling results identified key primary minerals as well as key chemical processes, but also showed that the models are not capable of covering all possible contingencies.  相似文献   

19.
A total of 73 oils from the sandstone reservoir of Paleocene–Eocene Sokor 1 Formation in the Termit Basin (eastern Niger) were analysed to investigate the distribution characteristics of biomarkers. Most of the oil samples are quite similar in their organic geochemical characteristics and should have been derived from the same source bed/source kitchen. The homogenisation temperatures of aqueous inclusions in Paleocene–Eocene reservoir of the Termit Basin vary with a range of 76–125?°C. By combining the homogenisation temperatures with the burial and geothermal histories reconstructed by 1-dimensional basin modelling, the timing and episode of oil charge can be obtained, i.e. 13 to 0?Ma for Paleocene–Eocene reservoirs in the Termit Basin. Two presentative geochemical parameters, i.e. Ts / (Ts?+?Tm) and 2,4-dibenzothiophene/1,4-dibenzothiophene (2,4-DMDBT/1,4-DMDBT) were applied to trace the oil migration direction and filling pathway. The preferred oil-filling points in the northwest section of the Termit Basin were determined, and the promising exploratory targets were proposed for further oil exploration in this region.  相似文献   

20.
Sequestration of CO2 into a deep geological reservoir causes a complex interaction of different processes such as multiphase flow, phase transition, multicomponent transport, and geochemical reactions between dissolved CO2 and the mineral matrix of the porous medium. A prognosis of the reservoir behaviour and the feedback from large-scale geochemical alterations require efficient process-based numerical models. For this purpose, the multiphase flow and multicomponent transport code OpenGeoSys-Eclipse have been coupled to the geochemical model ChemApp. The newly developed coupled simulator was successfully verified for correctness and accuracy of the implemented reaction module by benchmarking tests. The code was then applied to assess the impact of geochemical reactions during CO2 sequestration at a hypothetical but typical Bunter sandstone formation in the Northern German Basin. Injection and spreading of 1.48 × 107 t of CO2 in an anticline structure of the reservoir were simulated over a period of 20 years of injection plus 80 years of post-injection time. Equilibrium geochemical calculations performed by ChemApp show only a low reactivity to the geochemical system. The increased acidity of the aqueous solution results in dissolution of small amounts of calcite, anhydrite, and quartz. Geochemical alterations of the mineral phase composition result in slight increases in porosity and permeability, which locally may reach up to +0.02 and 0.1 %, respectively.  相似文献   

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