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1.
After completion of an exploration well, sandstones of the Exter Formation were hydraulically tested to determine the hydraulic properties and to evaluate chemical and microbial processes caused by drilling and water production. The aim was to determine the suitability of the formation as a reservoir for aquifer thermal energy storage. The tests revealed a hydraulic conductivity of 1–2 E-5 m/s of the reservoir, resulting in a productivity index of 0.6–1 m3/h/bar. A hydraulic connection of the Exter Formation to the overlaying, artesian “Rupelbasissand” cannot be excluded. Water samples were collected for chemical and microbiological analyses. The water was similarly composed as sea water with a maximum salinity of 24.9 g/L, dominated by NaCl (15.6 g/L Cl and 7.8 g/L Na). Until the end of the tests, the water was affected by drilling mud as indicated by the high pH (8.9) and high bicarbonate concentration (359 mg/L) that both resulted from the impact of sodium carbonate (Na2CO3) additives. The high amount of dissolved organic matter (>?58 mg/L) and its molecular-weight distribution pattern indicated that residues of cellulose, an ingredient of the drilling mud, were still present at the end of the tests. Clear evidence of this contamination gave the measured uranine that was added as a tracer into the drilling mud. During fluid production, the microbial community structure and abundance changed and correlated with the content of drilling mud. Eight taxa of sulfate-reducing bacteria, key organisms in processes like bio-corrosion and bio-clogging, were identified. It can be assumed that their activity will be affected during usage of the reservoir.  相似文献   

2.
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   

3.
Deep saline aquifers in sedimentary basins are considered to have the greatest potential for CO2 geological storage in order to reduce carbon emissions. CO2 injected into a saline sandstone aquifer tends to migrate upwards toward the caprock because the density of the supercritical CO2 phase is lower than that of formation water. The accumulated CO2 in the upper portions of the reservoir gradually dissolves into brine, lowers pH and changes the aqueous complexation, whereby induces mineral alteration. In turn, the mineralogical composition could impose significant effects on the evolution of solution, further on the mineralized CO2. The high density of aqueous phase will then move downward due to gravity, give rise to “convective mixing,” which facilitate the transformation of CO2 from the supercritical phase to the aqueous phase and then to the solid phase. In order to determine the impacts of mineralogical compositions on trapping amounts in different mechanisms for CO2 geological storage, a 2D radial model was developed. The mineralogical composition for the base case was taken from a deep saline formation of the Ordos Basin, China. Three additional models with varying mineralogical compositions were carried out. Results indicate that the mineralogical composition had very obvious effects on different CO2 trapping mechanisms. Specific to our cases, the dissolution of chlorite provided Mg2+ and Fe2+ for the formation of secondary carbonate minerals (ankerite, siderite and magnesite). When chlorite was absent in the saline aquifer, the dominant secondary carbon sequestration mineral was dawsonite, and the amount of CO2 mineral trapping increased with an increase in the concentration of chlorite. After 3000 years, 69.08, 76.93, 83.52 and 87.24 % of the injected CO2 can be trapped in the solid (mineral) phase, 16.05, 11.86, 8.82 and 6.99 % in the aqueous phase, and 14.87, 11.21, 7.66 and 5.77 % in the gas phase for Case 1 through 4, respectively.  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.
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   

6.
Niutuozhen geothermal field is located in the Jizhong graben, belonging to the northern part of Bohai Bay Basin in North China. Chemical and isotopic analyses were carried out on 14 samples of the geothermal fluids discharged from Neogene Minghuazhen (Nm), Guantao (Ng), and Jixianian Wumishan (Jxw) formations. The δ2H and δ18O in water, δ13C in CH4, δ13C in CO2, and 3He/4He ratio in the gases were analyzed in combination with chemical analyses on the fluids in the Niutuozhen geothermal field. The chemical and isotopic compositions indicate a meteoric origin of the thermal waters. The reservoir temperatures estimated by chemical geothermometry are in the range between 60 and 108 °C. The results show that the gases are made up mainly by N2 (18.20–97.42 vol%), CH4 (0.02–60.95 vol%), and CO2 (0.17–25.14 vol%), with relatively high He composition (up to 0.52 vol%). The chemical and isotopic compositions of the gas samples suggest the meteoric origin of N2, predominant crustal origins of CH4, CO2, and He. The mantle-derived He contributions are calculated to be from 5 to 8% based on a crust–mantle binary mixing model. The deep temperatures in the Jxw reservoir were evaluated based on gas isotope geothermometry to be in the range from 141 to 165 °C. The mantle-derived heat fraction in the surface heat flow is estimated to be in the range of 48–51% based on 3He/4He ratios.  相似文献   

7.
An “on-line” mixing system has been developed and evaluated for continuous oxygen isotope exchange between gas-phase CO2 and liquid water. The system is composed of three basic parts: equipment and materials used to introduce water and gas into a mixing reservoir, the mixing and exchange reservoir, and a vessel used to separate gas and water phases exiting the system. A series of experiments were performed to monitor the isotope exchange process over a range of temperatures (5–40 °C) and CO2 partial pressures (202–15,200 Pa). Isotopic exchange was evaluated using CO2 having δ18O values of 30.4 and 37.8 ‰ and waters of two distinct oxygen isotope compositions (?6.5 to ?5 and 6 to 7.5 ‰). Isotope ratios were determined by isotope ratio mass spectrometry and cavity ring-down spectroscopy. CO2 did not reach oxygen isotope equilibrium under the conditions described here. However, oxygen isotope exchange rate constants were determined at different temperatures and regressed to yield the expression k (h?1) = 0.020 × T (°C) + 0.28. Using this expression, the residence time required to reach oxygen isotope equilibrium may be estimated for a given set of environmental conditions (e.g., δ18O value of water, temperature). System parameters can be modified to achieve a specific δ18O value for CO2. Consequently, the exchange system described here has the ability to deliver a constant flow of CO2 at a desired oxygen isotope composition. This ability is attractive for a variety of applications such as experiments that utilize flow-through reactors and environmental chambers or require static chemical conditions.  相似文献   

8.
Geochemical detection of carbon dioxide in dilute aquifers   总被引：1，自引：0，他引：1  

Background  

Carbon storage in deep saline reservoirs has the potential to lower the amount of CO2 emitted to the atmosphere and to mitigate global warming. Leakage back to the atmosphere through abandoned wells and along faults would reduce the efficiency of carbon storage, possibly leading to health and ecological hazards at the ground surface, and possibly impacting water quality of near-surface dilute aquifers. We use static equilibrium and reactive transport simulations to test the hypothesis that perturbations in water chemistry associated with a CO2 gas leak into dilute groundwater are important measures for the potential release of CO2 to the atmosphere. Simulation parameters are constrained by groundwater chemistry, flow, and lithology from the High Plains aquifer. The High Plains aquifer is used to represent a typical sedimentary aquifer overlying a deep CO2 storage reservoir. Specifically, we address the relationships between CO2 flux, groundwater flow, detection time and distance. The CO2 flux ranges from 103 to 2 × 106 t/yr (0.63 to 1250 t/m2/yr) to assess chemical perturbations resulting from relatively small leaks that may compromise long-term storage, water quality, and surface ecology, and larger leaks characteristic of short-term well failure.  相似文献   

9.
Variations in the carbon isotope composition in gases and waters of mud volcanoes in the Taman Peninsula are studied. The δ13C values in CH4 and CO2 vary from ?59.5 to ?44.0‰ (δ13Cav = ?52.4 ± 5.4‰) and from ?17.8 to +22.8‰ (δ13Cav = +6.9 ± 9.3‰), respectively. In waters from most mud volcanoes of the peninsula, this parameter ranges from +3.3 to +33.1‰, although locally lower values are also recorded (up to ?12‰. Fractionation of carbon isotopes in the CO2-HCO3 system corresponds to the isotope equilibrium under Earth’s surface temperatures. The growth of carbon dioxide concentration in the gaseous phase and increase in the HCO3 ion concentration in their water phase is accompanied by the enrichment of the latter with the heavy 13C isotope. The δ13CTDIC value in the water-soluble carbon depends on the occurrence time of water on the Earth’s surface (exchange with atmospheric CO2, methane oxidation, precipitation of carbonates, and other processes), in addition to its primary composition. In this connection, fluctuations in δ13CTDIC values in mud volcanoes with stagnant waters may amount to 10–20‰. In the clayey pulp, concentrations of carbonate matter recalculated to CaCO3 varies from 1–4 to 36–50 wt %. The δ13C value in the latter ranges from ?3.6 to +8.4‰. Carbonate matter of the clayey pulp represents a mixture of sedimentogenic and authigenic carbonates. Therefore, it is usually unbalanced in terms of the carbon isotope composition with the water-soluble CO2 forms.  相似文献   

10.
Properties of geothermal resources in Kebilli region, Southwestern Tunisia   总被引：2，自引：2，他引：0  
The Kebilli region is located in the Southwestern part of Tunisia, and is characterized by the presence of deep and shallow geothermal systems (continental intercalary and complex terminal). Chemical and isotopic contents are used to classify the type and determine the origin of thermal water. An evaluation of reservoir temperature and a possible geothermal fluid mixing are also carried out. Both continental intercalary-deep aquifer and complex terminal-shallow aquifer are of Na–(Ca)–Cl–(SO4) mixed water type. The use of different geothermometers and the computation of saturation indexes for different solid phases suggests that the thermal reservoir temperature of the continental intercalary is between 92 and 105 °C, while the fluid temperature from the shallow complex terminal aquifer ranges from 50 to 75 °C. Also, the isotopic data indicates the old origin of all groundwater of Southwestern Tunisia. Mixing effects characterizing the continental intercalary and the complex terminal aquifers were identified using δ2H and δ18O relationship. It appears that the upward movement of thermal water from the deep aquifer to shallow ones is probably due to the abundant fractures in the research area.  相似文献   

11.
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   

12.
Deep brine recovery enhanced by supercritical CO2 injection is proposed to be a win–win method for the enhancement of brine production and CO2 storage capacity and security. However, the cross-flow through interlayers under different permeability conditions is not well investigated for a multi-layer aquifer system. In this work, a multi-layer aquifer system with different permeability conditions was built up to quantify the brine production yield and the leakage risk under both schemes of pure brine recovery and enhanced by supercritical CO2. Numerical simulation results show that the permeability conditions of the interlayers have a significant effect on the brine production and the leakage risk as well as the regional pressure. Brine recovery enhanced by supercritical CO2 injection can improve the brine production yield by a factor of 2–3.5 compared to the pure brine recovery. For the pure brine recovery, strong cross-flow through interlayers occurs due to the drastic and extensive pressure drop, even for the relative low permeability (k = 10?20 m2) mudstone interlayers. Brine recovery enhanced by supercritical CO2 can successfully manage the regional pressure and decrease the leakage risk, even for the relative high permeability (k = 10?17 m2) mudstone interlayers. In addition, since the leakage of brine mainly occurs in the early stage of brine production, it is possible to minimize the leakage risk by gradually decreasing the brine production pressure at the early stage. Since the leakage of CO2 occurs in the whole production period and is significantly influenced by the buoyancy force, it may be more effective by adopting horizontal wells and optimizing well placement to reduce the CO2 leakage risk.  相似文献   

13.
The surface sediments of two mud mounds (“Mound 11” and “Mound 12”) offshore southwest Costa Rica contain abundant authigenic carbonate concretions dominated by high-Mg calcite (14–20 mol-% MgCO3). Pore fluid geochemical profiles (sulfate, sulfide, methane, alkalinity, Ca and Mg) indicate recent carbonate precipitation within the zone of anaerobic oxidation of methane (AOM) at variable depths. The current location of the authigenic carbonate concretions is, however, not related to the present location of the AOM zone, suggesting mineral precipitation under past geochemical conditions as well as changes in the flow rates of upward migrating fluids. Stable oxygen and carbon isotope analysis of authigenic carbonate concretions yielded δ18Ocarbonate values ranging between 34.0 and 37.7 ‰ Vienna standard mean ocean water (VSMOW) and δ13Ccarbonate values from ?52.2 to ?14.2 ‰ Vienna Pee Dee belemnite (VPDB). Assuming that no temperature changes occurred during mineral formation, the authigenic carbonate concretions have been formed at in situ temperature of 4–5 °C. The δ18Ocarbonate values suggest mineral formation from seawater-derived pore fluid (δ18Oporefluid = 0 ‰ VSMOW) for Mound 12 carbonate concretions but also the presence of an emanating diagenetic fluid (δ18Oporefluid ≈5 ‰) in Mound 11. A positive correlation between δ13Ccarbonate and δ18Ocarbonate is observed, indicating the admixing of two different sources of dissolved carbon and oxygen in the sediments of the two mounds. The carbon of these sources are (1) marine bicarbonate (δ13Cporefluid ≈0 ‰) and (2) bicarbonate which formed during the AOM (δ13Cporefluid ≈?70 ‰). Furthermore, the δ18Oporefluid composition, with values up to +4.7 ‰ Vienna standard mean ocean water (VSMOW), is interpreted to be affected by the presence of emanating, freshened and boron-enriched fluids. Earlier, it has been shown that the origin of 18O-enriched fluids are deep diagenetic processes as it was indicated by the presence of methane with thermogenic signature (δ13CCH4 = ?38 ‰). A combination of present geochemical data with geophysical observations indicates that Mounds 11 and 12 represent a single fluid system interconnected by deep-seated fault(s).  相似文献   

14.
The hydrogeochemistry and isotope geochemistry of groundwater from 85 wells in fractured dolomite aquifers of Central Slovenia were investigated. This groundwater represents waters strongly influenced by chemical weathering of dolomite with an average of δ13CCARB value of +2.2 ‰. The major groundwater geochemical composition is HCO3 ? > Ca2+ > Mg2+. Several differences in hydrogeochemical properties among the classes of dolomites were observed when they were divided based on their age and sedimentological properties, with a clear distinction of pure dolomites exhibiting high Mg2+/Ca2+ ratios and low Na+, K+ and Si values. Trace element and nutrient concentrations (SO4 2?, NO3 ?) were low, implying that karstic and fractured dolomite aquifers are of good quality to be used as tap water. Groundwater was generally slightly oversaturated with respect to calcite and dolomite, and dissolved CO2 was up to 46 times supersaturated relative to the atmosphere. The isotopic composition of oxygen (δ18OH2O), hydrogen (δDH2O) and tritium ranged from ?10.3 to ?8.4 ‰, from ?68.5 to ?52.7 ‰ and from 3.5 TU to 10.5 TU, respectively. δ18O and δD values fell between the GMWL (Global Meteoric Water Line) and the MMWL (Mediterranean Meteoric Water Line) and indicate recharge from precipitation with little evaporation. The tritium activity in groundwater suggests that groundwater is generally younger than 50 years. δ13CDIC values ranged from ?14.6 to ?9.3 ‰ and indicated groundwater with a contribution of degraded organic matter/dissolved inorganic carbon in the aquifer. The mass balances for groundwater interacting with carbonate rocks suggested that carbonate dissolution contributes from 43.7 to 65.4 % and degradation of organic matter from 34.6 to 56.3 %.  相似文献   

15.
A geochemical survey, in shallow aquifers and soils, has been carried out to evaluate the feasibility of natural gas (CH4) storage in a deep saline aquifer at Rivara (MO), Northern Italy. This paper discusses the areal distribution of CO2 and CH4 fluxes and CO2, CH4, Rn, He, H2 concentrations both in soils and shallow aquifers above the proposed storage reservoir. The distribution of pathfinder elements such as 222Rn, He and H2 has been studied in order to identify potential faults and/or fractures related to preferential migration pathways and the possible interactions between the reservoir and surface. A geochemical and isotopic characterization of the ground waters circulating in the first 200 m has allowed to investigation of (i) the origin of the circulating fluids, (ii) the gas–water–rock interaction processes, (iii) the amount of dissolved gases and/or their saturation status. In the first 200 m, the presence of CH4-rich reducing waters are probably related to organic matter (peat) bearing strata which generate shallow-derived CH4, as elsewhere in the Po Plain. On the basis of isotopic analysis, no hints of thermogenic CH4 gas leakage from a deeper reservoir have been shown. The δ13C(CO2) both in ground waters and free gases suggests a prevalent shallow origin of CO2 (i.e. organic and/or soil-derived). The acquisition of pre-injection data is strategic for the natural gas storage development project and as a baseline for future monitoring during the gas injection/withdrawing period. Such a geochemical approach is considered as a methodological reference model for future CO2/CH4 storage projects.  相似文献   

16.
《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   

17.
The buildup of high pressure in the casing-casing annulus (CCA) threatens well integrity and can cause serious incidents in case of left untreated. Either, trapped water in the cement column or a dynamic water inflow represent potential fluid sources for the elevated CCA pressure. This study presents a sequential methodology to determine the provenance of CCA effluent as trigger for high pressure in newly drilled wells. Single fluid types, multicomponent mixing, and secondary fluid alteration processes were identified through inorganic geochemical techniques; in detail by monitoring the hydrochemical (major, minor, and trace elements) and stable isotopic (δ2H, δ18O) relationship between fluid candidates. As a proof-of-concept, geochemical signatures of CCA effluent from three wells were linked with potential source candidates, i.e., utilized drilling fluids (mud filtrate, supply water) from the prospect well site, groundwater from Lower - Upper Cretaceous aquifers, and Upper Jurassic - Upper Triassic formation waters from adjacent wells and fields. The detection of geochemical affinities of CCA water with groundwater from a Lower Cretaceous aquifer postulates one single lithological unit as source for active groundwater inflow. Nonreactive elements (Na+, Cl−) and environmental isotopes (δ2H, δ18O) were found to be most suited tools for primary fluid identification. The 2H/1H and 18O/16O ratios of supply water and mud filtrate are generally close to global meteoric water and Tertiary groundwater composition, while formation water from Mesozoic units (Cretaceous, Jurassic, and Triassic) can individually be distinguished through increasing ratios in δ18O and δ2H. Compositional anomalies in SO42− and K+, and extreme alkaline conditions for CCA water indicate the occurrence of secondary fluid alteration processes, likely caused by the contact of inflowing groundwater with alkaline minerals in the cement column or by fluid mixing with residuals of potassium chloride (KCl) additives from the drilling process. The geochemical techniques from this study facilitate the detection of high CCA pressure and fluid leakages sources. As a practical benefit, workover engineers are enabled to plan for potential remedial actions prior to moving the rig to affected well sites; thereby significantly reducing operational costs. Appropriate remedial solutions can be induced for safe well abandonment, plus to resume operation at the earliest time.  相似文献   

18.
Stable isotopes of injected CO2 act as useful tracers in carbon capture and storage (CCS) because the CO2 itself is the carrier of the tracer signal and remains unaffected by sorption or partitioning effects. At the Ketzin pilot site (Germany), carbon stable isotope composition (δ13C) of injected CO2 at the injection well was analyzed over a time period of 4 months. Occurring isotope variances resulted from the injection of CO2 from two different sources (an oil refinery and a natural gas-reservoir). The two gases differed in their carbon isotope composition by more than 27‰. In order to find identifiable patterns of these variances in the reservoir, more than 250 CO2-samples were collected and analyzed for their carbon isotope ratios at an observation well 100 m distant from the injection well. An isotope ratio mass spectrometer connected to a modified Thermo Gasbench system allowed quick and cost effective isotope analyses of a high number of CO2 gas specimens. CO2 gas from the oil refinery (δ13C = −30.9‰, source A) was most frequently injected and dominated the reservoir δ13C values at the injection site. Sporadic injection of the CO2 from the natural gas-reservoir (δ13C = −3.5‰, source B) caused isotope shifts of up to +5‰ at the injection well. These variances provided a potential ideal tracer for CO2 migration behavior. Based on these findings, tracer input signals that were injected during the last 2 years of injection could be reconstructed with the aid of an isotope mixing model and CO2 delivery schedules. However, in contrast to the injection well, δ13C values at the observation well showed no variances and a constant value of −28.5‰ was measured at 600 m depth. This is in disagreement with signals that would be expected if the input signals from the injection would arrive at the observation well. The lack of isotope signals at the observation well suggests that parts of the reservoir are filled with CO2 that is immobilized.  相似文献   

19.
The Kangan Permo-Triassic brine aquifer and the overlying gas reservoir in the southern Iran are located in Kangan and Dalan Formations, consisting dominantly of limestone, dolomite, and to a lesser extent, shale and anhydrite. The gasfield, 2,900 m in depth and is exploited by 36 wells, some of which produce high salinity water. The produced water gradually changed from fresh to saline, causing severe corrosion in the pipelines and well head facilities. The present research aims to identify the origin of this saline water (brine), as a vital step to manage saline water issues. The major and minor ions, as well as δ2H, δ18O and δ37Cl isotopes were measured in the Kangan aquifer water and/or the saline produced waters. The potential processes causing salinity can be halite dissolution, membrane filtration, and evaporation of water. The potential sources of water may be meteoric, present or paleo-seawater. The Na/Cl and I/Cl ratios versus Cl? concentration preclude halite dissolution. Concentrations of Cl, Na, and total dissolved solid were compared with Br concentration, indicating that the evaporated ancient seawater trapped in the structure is the cause of salinization. δ18O isotope enrichment in the Kangan aquifer water is due to both seawater evaporation and interaction with carbonate rocks. The δ37Cl isotope content also supports the idea of evaporated ancient seawater as the origin of salinity. Membrane filtration is rejected as a possible source of salinity based on the hydrochemistry data, the δ18O value, and incapability of this process to dramatically enhance salinity up to the observed value of 330,000 mg/L. The overlaying impermeable formations, high pressure in the gas reservoir, and the presence of a cap rock above the Kangan gasfield, all prevent the downward flow of meteoric and Persian Gulf waters into the Kangan aquifer. The evaporated ancient seawater is autochthonous, because the Kangan brine aquifer was formed by entrapment of brine seawater during the deposition of carbonates, gypsum, and minor clastic rocks in a lagoon and sabkha environment. The reliability of determining the source of salinity in a deep complicated inaccessible high-pressure aquifer can be improved by combining various methods of hydrochemistry, isotope, hydrodynamics, hydrogeology and geological settings.  相似文献   

20.
This study examined the impacts of reservoir properties on carbon dioxide (CO2) migration after subsurface injection and evaluated the possibility of characterizing reservoir properties using CO2 monitoring data such as spatial–temporal distributions of gas pressure, which can be reasonably monitored in practice. The injection reservoir was assumed to be located 1,400–1,500 m below the ground surface such that CO2 remained in the supercritical state. The reservoir was assumed to contain layers with alternating conductive and resistive properties, which is analogous to actual geological formations such as the Mount Simon Sandstone unit. The CO2 injection simulation used a cylindrical grid setting in which the injection well was situated at the center of the domain, which extended out 8,000 m from the injection well. The CO2 migration was simulated using the latest version of the simulator, subsurface transport over multiple phases (the water–salt–CO2–energy module), developed by Pacific Northwest National Laboratory. A nonlinear parameter estimation and optimization modeling software package, Parameter ESTimation (PEST), is adopted for automated reservoir parameter estimation. The effects of data quality, data worth, and data redundancy were explored regarding the detectability of reservoir parameters using gas pressure monitoring data, by comparing PEST inversion results using data with different levels of noises, various numbers of monitoring wells and locations, and different data collection spacing and temporal sampling intervals. This study yielded insight into the use of CO2 monitoring data for reservoir characterization and how to design the monitoring system to optimize data worth and reduce data redundancy. The feasibility of using CO2 saturation data for improving reservoir characterization was also discussed.  相似文献   

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