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

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.     

The impact of diagenetic fluid–rock reactions on Rotliegend sandstone composition and petrophysical properties (Altmark area, central Germany)

In the framework of the German R&D joint project CLEAN (CO₂ large-scale enhanced gas recovery in the Altmark natural gas field), Rotliegend reservoir sandstones of the Altensalzwedel block in the Altmark area (Saxony-Anhalt, central Germany) have been studied to characterise litho- and diagenetic facies, mineral content, geochemical composition, and petrophysical properties. These sands have been deposited in a playa environment dominated by aeolian dunes, dry to wet sand flats and fluvial channel fills. The sediments exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. In sandstones of the damp to wet sandflats, their pristine red colours are preserved and porosity and permeability are only low. Rocks of the aeolian environment and most of the channel fill deposits are preferentially bleached and exhibit moderate to high porosity and permeability. Although geochemical element whole rock content in these rocks is very similar, element correlations are different. Variations in porosity and permeability are mainly due to calcite and anhydrite dissolution and differences in clay coatings with Fe-bearing illitic-chloritic composition exposed to the pore space. Moreover, mineral dissolution patterns as well as compositions (of clays and carbonate) and morphotypes of authigenic minerals (chlorite, illite) are different in red and bleached rocks. Comparison of the geochemical composition and mineralogical features of diagenetically altered sandstones and samples exposed to CO₂-bearing fluids in laboratory batch experiments exhibit similar character. Experiments prove an increase in wettability and water binding capacity during CO₂ impact.     

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

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.     

Analyses of pre-injection reservoir data for stable carbon isotope trend predictions in CO2 monitoring: preparing for CO2 injection

Baseline monitoring at the proposed enhanced gas recovery site in Altmark (Germany) was carried out in combination with theoretical and laboratory investigations to describe and predict the principles of expected stable carbon isotope and dissolved inorganic carbon (DIC) trends during CO₂ injection in reservoirs. This provides fundamental data for site-specific characterisation for monitoring purposes. Baseline ??¹³C values at the Altmark site ranged between ?1.8 and ?11.5??? and DIC values were about 2?mmol?L^?1. These baseline values form the basis for a theoretical study on the influences of the ambient reservoir conditions on the state of geochemical and isotope equilibrium of the reservoir fluids. Transferring this theoretical study to the Altmark site enables predictions on geochemical trends during potential injection. Assuming that CO₂ would be injected at the Altmark site to pCO₂?=?100?bar and with a ??¹³C of ?30???, at isotopic and geochemical equilibrium, ??¹³C_DIC values would approach this end-member, and DIC concentrations of 1,000?mmol L^?1 would be expected. Laboratory experiments were conducted at low pCO₂ levels (4?C35?bars) to mimic the approach of a CO₂ plume at a monitoring well. These results support field investigations from other sites: that ??¹³C_DIC is a sensitive tool for monitoring CO₂ migration in the subsurface and simultaneously allows quantification of geochemical trapping of CO₂.     

Chemical changes in fluid composition due to CO2 injection in the Altmark gas field: preliminary results from batch experiments

Dissolution?Cprecipitation phenomena induced by CO₂ injection to Altmark Permian sandstone were observed through laboratory experiments carried out under simulated reservoir conditions (125?°C and 50 bars of pressure). The rock sample was collected from the Altmark gas reservoir, which is being considered for enhanced gas recovery. Two sets of experiments were performed with pulverized rock samples in a closed batch reactor with either pure water (run 1) or 3?M aqueous NaCl solution (run 2) and reacted with injected CO₂ for 3, 5, and 9?days. The liquid samples were analyzed by inductively coupled plasma optical emission spectroscopy and total reflection X-ray fluorescence, where the latter proved to be a feasible alternative to conventional analytical techniques, especially since only small sample volumes (about 10???l) are needed. Chemical analysis for both fluids (water and NaCl brine) indicated a significant dissolution of calcite and anhydrite in the solution, which might be a crucial process during CO₂ injection. The brine solution enhanced the dissolution of calcite and anhydrite compared to pure water at the beginning of the reaction. Moreover, the progressive higher Si⁴⁺/Al³⁺ molar ratios (in average by a factor of 3) in the brine experiments indicated quartz dissolution. Thermodynamic calculations of mineral saturation indices highlighted the dissolution of the Ca-bearing minerals, which was in agreement with experimental results. Modeling enabled an evaluation of the dissolution processes of minerals in a low-salinity region, yet hindrances to model more saline conditions emphasize the need for further laboratory studies in order to parameterize models for deep aquifer conditions.     

Sensitivity study of pulsed neutron-gamma saturation monitoring at the Altmark site in the context of CO2 storage

The injection of CO₂ into depleted natural gas reservoirs has been proposed as a promising new technology for combining enhanced gas recovery and geological storage of CO₂. During the injection, application of suitable techniques for monitoring of the induced changes in the subsurface is required. Observing the movement and the changes in saturation of the fluids contained in the reservoir and the confining strata is among the primary aims here. It is shown that under conditions similar to the Altmark site, Germany, pulsed neutron-gamma logging can be applied with limitations. The pulsed neutron-gamma method can be applied for detection and quantification of changes in brine saturation and water content, whereas changes in the gas composition are below the detection limit. A method to account for the effects of salt precipitation resulting from evaporation of residual brine is presented.     

Thermo-hydro-mechanical modeling of carbon dioxide injection for enhanced gas-recovery (CO2-EGR): a benchmarking study for code comparison

The objective of this paper was to investigate the THM-coupled responses of the storage formation and caprock, induced by gas production, CO₂-EGR (enhanced gas recovery), and CO₂-storage. A generic 3D planer model (20,000?×?3,000?×?100?m, consisting of 1,200?m overburden, 100?m caprock, 200?m gas reservoir, and 1,500?m base rock) is adopted for the simulation process using the integrated code TOUGH2/EOS7C-FLAC3D and the multi-purpose simulator OpenGeoSys. Both simulators agree that the CO₂-EGR phase under a balanced injection rate (31,500?tons/year) will cause almost no change in the reservoir pressure. The gas recovery rate increases 1.4?% in the 5-year CO₂-EGR phase, and a better EGR effect could be achieved by increasing the distance between injection and production wells (e.g., 5.83?% for 5?km distance, instead of 1.2?km in this study). Under the considered conditions there is no evidence of plastic deformation and both reservoir and caprock behave elastically at all operation stages. The stress path could be predicted analytically and the results show that the isotropic and extensional stress regime will switch to the compressional stress regime, when the pore pressure rises to a specific level. Both simulators agree regarding modification of the reservoir stress state. With further CO₂-injection tension failure in reservoir could occur, but shear failure will never happen under these conditions. Using TOUGH-FLAC, a scenario case is also analyzed with the assumption that the reservoir is naturally fractured. The specific analysis shows that the maximal storage pressure is 13.6?MPa which is determined by the penetration criterion of the caprock.     

Development of a long-term wellbore sealing concept based on numerical simulations and in situ-testing in the Altmark natural gas field

This paper presents an innovative well abandonment concept developed for the long-term containment of CO₂ in depleted Rotliegend gas reservoirs. The new concept aims at amending the conventional standard well abandonment procedure, taking advantage of the natural creeping ability of the thick, homogeneous Zechstein rock salt formation located around 3,000?m in depth (Altmark area) and consists of four main sealing units: (1) a standard sealing element with cement from the reservoir to the impermeable caprock, (2) a salt plug created in the formerly reamed section of casing within the plastic Zechstein (Upper Permian) rock salt formation, (3) two bridge plugs at the bottom and top of the salt plug and (4) a standard sealing element with cement from the top bridge plug until the ground surface. This site-specific study mainly lays emphasis on the development and field testing of the naturally created salt plug, as a key component of the long-term wellbore sealing concept. Comprehensive numerical simulations conducted prior to and during the field test in 2010 and 2011 successfully predicted the evolution of convergence using downhole measurement data. Preliminary results comprise (1) proven convergence of the rock salt formation, (2) a successful coring and (3) restored integrity of Zechstein salt formation, as proven by the formation integrity test. Based on these results, the new long-term sealing concept has been successfully tested at the Altmark natural gas field and successful application of the concept on other sites with similar geological conditions is foreseen to be likely.     

Laboratory study of self-potential signals during releasing of CO2 and N2 plumes

Carbon Capture Sequestration (CCS) projects require, for safety reasons, monitoring programmes focused on surveying gas leakage on the surface. Generally, these programmes include detection of chemical tracers that, once on the surface, could be associated with CO₂ degassing. We take a different approach by analysing feasibility of applying electrical surface techniques, specifically Self-Potential. A laboratory-scale model, using water-sand, was built for simulating a leakage scenario being monitored with non-polarisable electrodes. Electrical potentials were measured before, during and after gas injection (CO₂ and N₂) to determine if gas leakage is detectable. Variations of settings were done for assessing how the electrical potentials changed according to size of electrodes, distance from electrodes to the gas source, and type of gas. Results indicated that a degassing event is indeed detectable on electrodes located above injection source. Although the amount of gas could not be quantified from signals, injection timespan and increasing of injection rate were identified. Even though conditions of experiments were highly controlled contrasting to those usually found at field scale, we project that Self-Potential is a promising tool for detecting CO₂ leakage if electrodes are properly placed.     

Effect of injected CO2 on geochemical alteration of the Altmark gas reservoir in Germany

Capturing CO₂ from point sources and storing it in geologic formations is a potential option for allaying the CO₂ level in the atmosphere. In order to evaluate the effect of geological storage of CO₂ on rock-water interaction, batch experiments were performed on sandstone samples taken from the Altmark reservoir, Germany, under in situ conditions of 125 °C and 50 bar CO₂ partial pressure. Two sets of experiments were performed on pulverized sample material placed inside a closed batch reactor in (a) CO₂ saturated and (b) CO₂ free environment for 5, 9 and 14 days. A 3M NaCl brine was used in both cases to mimic the reservoir formation water. For the “CO₂ free” environment, Ar was used as a pressure medium. The sandstone was mainly composed of quartz, feldspars, anhydrite, calcite, illite and chlorite minerals. Chemical analyses of the liquid phase suggested dissolution of both calcite and anhydrite in both cases. However, dissolution of calcite was more pronounced in the presence of CO₂. In addition, the presence of CO₂ enhanced dissolution of feldspar minerals. Solid phase analysis by X-ray diffraction and Mössbauer spectroscopy did not show any secondary mineral precipitation. Moreover, Mössbauer analysis did not show any evidence of significant changes in redox conditions. Calculations of total dissolved solids’ concentrations indicated that the extent of mineral dissolution was enhanced by a factor of approximately 1.5 during the injection of CO₂, which might improve the injectivity and storage capacity of the targeted reservoir. The experimental data provide a basis for numerical simulations to evaluate the effect of injected CO₂ on long-term geochemical alteration at reservoir scale.     

Site characterization for CO<Subscript>2</Subscript> geologic storage and vice versa: the Frio brine pilot,Texas, USA as a case study

Careful site characterization is critical for successful geologic storage of carbon dioxide (CO₂) because of the many physical and chemical processes impacting CO₂ movement and containment under field conditions. Traditional site characterization techniques such as geological mapping, geophysical imaging, well logging, core analyses, and hydraulic well testing provide the basis for judging whether or not a site is suitable for CO₂ storage. However, only through the injection and monitoring of CO₂ itself can the coupling between buoyancy flow, geologic heterogeneity, and history-dependent multi-phase flow effects be observed and quantified. CO₂ injection and monitoring can therefore provide a valuable addition to the site-characterization process. Additionally, careful monitoring and verification of CO₂ plume development during the early stages of commercial operation should be performed to assess storage potential and demonstrate permanence. The Frio brine pilot, a research project located in Dayton, Texas (USA) is used as a case study to illustrate the concept of an iterative sequence in which traditional site characterization is used to prepare for CO₂ injection and then CO₂ injection itself is used to further site-characterization efforts, constrain geologic storage potential, and validate understanding of geochemical and hydrological processes. At the Frio brine pilot, in addition to traditional site-characterization techniques, CO₂ movement in the subsurface is monitored by sampling fluid at an observation well, running CO₂-saturation-sensitive well logs periodically in both injection and observation wells, imaging with crosswell seismic in the plane between the injection and observation wells, and obtaining vertical seismic profiles to monitor the CO₂ plume as it migrates beyond the immediate vicinity of the wells. Numerical modeling plays a central role in integrating geological, geophysical, and hydrological field observations.     

The noble gas geochemistry of natural CO2 gas reservoirs from the Colorado Plateau and Rocky Mountain provinces, USA

Identification of the source of CO₂ in natural reservoirs and development of physical models to account for the migration and interaction of this CO₂ with the groundwater is essential for developing a quantitative understanding of the long term storage potential of CO₂ in the subsurface. We present the results of 57 noble gas determinations in CO₂ rich fields (>82%) from three natural reservoirs to the east of the Colorado Plateau uplift province, USA (Bravo Dome, NM., Sheep Mountain, CO. and McCallum Dome, CO.), and from two reservoirs from within the uplift area (St. John’s Dome, AZ., and McElmo Dome, CO.). We demonstrate that all fields have CO₂/³He ratios consistent with a dominantly magmatic source. The most recent volcanics in the province date from 8 to 10 ka and are associated with the Bravo Dome field. The oldest magmatic activity dates from 42 to 70 Ma and is associated with the McElmo Dome field, located in the tectonically stable centre of the Colorado Plateau: CO₂ can be stored within the subsurface on a millennia timescale.The manner and extent of contact of the CO₂ phase with the groundwater system is a critical parameter in using these systems as natural analogues for geological storage of anthropogenic CO₂. We show that coherent fractionation of groundwater ²⁰Ne/³⁶Ar with crustal radiogenic noble gases (⁴He, ²¹Ne, ⁴⁰Ar) is explained by a two stage re-dissolution model: Stage 1: Magmatic CO₂ injection into the groundwater system strips dissolved air-derived noble gases (ASW) and accumulated crustal/radiogenic noble gas by CO₂/water phase partitioning. The CO₂ containing the groundwater stripped gases provides the first reservoir fluid charge. Subsequent charges of CO₂ provide no more ASW or crustal noble gases, and serve only to dilute the original ASW and crustal noble gas rich CO₂. Reservoir scale preservation of concentration gradients in ASW-derived noble gases thus provide CO₂ filling direction. This is seen in the Bravo Dome and St. John’s Dome fields. Stage 2: The noble gases re-dissolve into any available gas stripped groundwater. This is modeled as a Rayleigh distillation process and enables us to quantify for each sample: (1) the volume of groundwater originally ‘stripped’ on reservoir filling; and (2) the volume of groundwater involved in subsequent interaction. The original water volume that is gas stripped varies from as low as 0.0005 cm³ groundwater/cm³ gas (STP) in one Bravo Dome sample, to 2.56 cm³ groundwater/cm³ gas (STP) in a St. John’s Dome sample. Subsequent gas/groundwater equilibration varies within all fields, each showing a similar range, from zero to ∼100 cm³ water/cm³ gas (at reservoir pressure and temperature).     

Production of gas from coal seams in the Upper Silesian Coal Basin in Poland in the post-injection period of an ECBM pilot site

A pilot site for CO₂ storage in coal seams was set-up in the Upper Silesian Coal Basin in Poland in the scope of the RECOPOL project, funded by the European Commission. About 760 tons CO₂ were injected into the reservoir from August 2004 to June 2005. Breakthrough of the injected CO₂ was established, which resulted in the production of about 10% of the injected CO₂ in this period. This paper reports on activities performed under the European Commission project MOVECBM that aimed at the assessment of the storage performance of the reservoir in the follow-up period, i.e. whether the injected CO₂ was adsorbed onto the coal or whether it was still present as free gas in the pore space. The injection well was used for this purpose, as the production well had to be abandoned for permitting reasons. Several operational periods can be defined between the last injection in June 2005 and the abandonment of the well in October 2007. In the first period the well was shut-in to observe the pressure fall-off, from about 15.0 MPa at the wellhead after the last injection until about 4.5 MPa at the end of 2005. This pressure fall-off curve showed that the reservoir permeability was very low. This seemed to confirm the observed swelling of the coal during the injection period. In the first months of 2006 the pressure at the wellhead was decreased by releasing gas in a controlled way. The amount and composition of the gas were measured. As a result of the pressure reduction, the well flooded with water. A production pump was placed on the former injection well, enabling active production from the coal from March to September 2007. Results of these operations showed that whereas the gas production rates were as expected based on the experience with the production well, the water production was remarkably low. This could be related to permeability issues or, alternatively, indicate a drying effect of the CO₂ in the reservoir. Further, the gas composition showed a predominance of CO₂ over CH₄ during the gas release that changed gradually into a predominance of CH₄ over CO₂ during the production phase. Although stabilization was not reached within the given production period, the composition approached a 60% methane, 40% CO₂ ratio. This indicates that the exchange of these gases is more complex than often envisaged. After removal of the pump the well was filled with water, which ceased the gas release. This indicates that the pressure in the reservoir was back to its original, hydrostatic, state. As the total volume of CO₂ produced was only a fraction of the amount that was injected, it can be concluded that the CO₂ was taken up by the coal and is currently adsorbed. This gives confidence in the long-term stability of the injected CO₂.     

A review of continuous soil gas monitoring related to CCS – Technical advances and lessons learned

One of the most vigorously discussed issues related to Carbon Capture and Storage (CCS) in the public and scientific community is the development of adequate monitoring strategies. Geological monitoring is mostly related to large scale migration of the injected CO₂ in the storage formations. However, public interest (or fear as that) is more related to massive CO₂ discharge at the surface and possible affects on human health and the environment. Public acceptance of CO₂ sequestration will only be achieved if secure and comprehensible monitoring methods for the natural habitat exist. For this reason the compulsory directive 2009/31/EG of the European Union as well as other international regulations demand a monitoring strategy for CO₂ at the surface. The variation of CO₂ emissions of different soil types and vegetation is extremely large. Hence, reliable statements on actual CO₂ emissions can only be made using continuous long-term gas-concentration measurements. Here the lessons learned from the (to the authors’ knowledge) first world-wide continuous gas concentration monitoring program applied on a selected site in the Altmark area (Germany), are described.This paper focuses on the authors’ technical experiences and recommendations for further extensive monitoring programs related to CCS. Although many of the individual statements and suggestions have been addressed in the literature, a comprehensive overview is presented of the main technical and scientific issues. The most important topics are the reliability of the single stations as well as range of the measured parameters. Each selected site needs a thorough pre-investigation with respect to the depth of the biologically active zone and potential free water level. For the site installation and interface the application of small drill holes is recommended for quantifying the soil gas by means of a closed circuit design. This configuration allows for the effective drying of the soil gas and avoids pressure disturbance in the soil gas. Standard soil parameters (humidity, temperature) as well as local weather data are crucial for site specific interpretation of the data. The complexity, time and effort to handle a dozen (or even more) single stations in a large case study should not be underestimated. Management and control of data, automatic data handling and presentation must be considered right from the beginning of the monitoring. Quality control is a pre-condition for reproducible measurements, correct interpretation and subsequently for public acceptance. From the experience with the recent monitoring program it is strongly recommended that baseline measurements should start at least 3 a before any gas injection to the reservoir.     

Geochemistry and episodic accumulation of natural gases from the Ledong gas field in the Yinggehai Basin, offshore South China Sea

The Ledong gas field, consisting of three gas pools in a shale diapir structure zone, is the largest gas discovery in the Yinggehai Basin. The gases produced from the Pliocene and Quaternary marine sandstone reservoirs show a considerable variation in chemical composition, with 5.4–88% CH₄, 0–93% CO₂, and 1–23.7% N₂. The CO₂-enriched gases often display heavier methane δ¹³C values than those with low CO₂ contents. The δ¹⁵N values of the gases range from −8 to −2‰, and the N₂ content correlates negatively with the CO₂ content. The high geothermal gradient associated with a relatively great burial depth in this area has led to the generation of hydrocarbon and nitrogen gases from the Lower–Middle Miocene source rocks and the formation of abundant CO₂ from the Tertiary calcareous-shales and pre-Tertiary carbonates. The compositional heterogeneities and stable carbon isotope data of the produced gases indicate that the formation of the LD221 gas field is attributed to three phases of gas migration: initially biogenic gas, followed by thermogenic hydrocarbon gas, and then CO₂-rich gas. The filling processes occurred within a short period approximately from 1.2 to 0.1 Ma based on the results of the kinetics modeling. Geophysical and geochemical data show that the diapiric faults that cut through Miocene sediments act as the main pathways for upward gas migration from the deep overpressured system into the shallow normal pressure reservoirs, and that the deep overpressure is the main driving force for vertical and lateral migration of the gases. This gas migration pattern implies that the transitional pressure zone around the shale diapir structures was on the pathway of upward migrating gases, and is also a favorable place for gas accumulation. The proposed multiple sources and multiple phases of gas migration and accumulation model for the Ledong gas field potentially provide useful information for the future exploration efforts in this area.     

Increased hydrocarbon recovery and CO2 management, a Croatian example

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.     

Europe’s longest-operating on-shore CO2 storage site at Ketzin, Germany: a progress report after three years of injection

The Ketzin pilot site, led by the GFZ German Research Centre for Geosciences, is Europe??s longest-operating on-shore CO₂ storage site with the aim of increasing the understanding of geological storage of CO₂ in saline aquifers. Located near Berlin, the Ketzin pilot site is an in situ laboratory for CO₂ storage in an anticlinal structure in the Northeast German Basin. Starting research within the framework of the EU project CO₂SINK in 2004, Ketzin is Germany??s first CO₂ storage site and fully in use since the injection began in June 2008. After 39?months of operation, about 53,000 tonnes of CO₂ have been stored in 630?C650?m deep sandstone units of the Upper Triassic Stuttgart Formation. An extensive monitoring program integrates geological, geophysical and geochemical investigations at Ketzin for a comprehensive characterization of the reservoir and the CO₂ migration at various scales. Integrating a unique field and laboratory data set, both static geological modeling and dynamic simulations are regularly updated. The Ketzin project successfully demonstrates CO₂ storage in a saline aquifer on a research scale. The results of monitoring and modeling can be summarized as follows: (1) Since the start of the CO₂ injection in June 2008, the operation has been running reliably and safely. (2) Downhole pressure data prove correlation between the injection rate and the reservoir pressure and indicates the presence of an overall dynamic equilibrium within the reservoir. (3) The extensive geochemical and geophysical monitoring program is capable of detecting CO₂ on different scales and gives no indication for any leakage. (4) Numerical simulations (history matching) are in good agreement with the monitoring results.     

Geochemistry of shallow aquifers and soil gas surveys in a feasibility study at the Rivara natural gas storage site (Po Plain,Northern Italy)

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.     

Increased hydrocarbon recovery and CO2 storage in Neogene sandstones,a Croatian example: part II

During 2003–2006, a pilot project of alternating water and CO₂ injection was performed on a limited part of the Upper Miocene sandstone oil reservoir of the Ivani? Field. During the test period oil and gas recovery was significantly increased. Additionally 4,440 m³ of oil and 2.26 × 10⁶ m³ of gas were produced. It has initiated further modelling of sandstone reservoirs in the Ivani? Field in order to calculate volumes available for CO₂ injection for the purpose of increasing hydrocarbon production from depleted sandstone reservoirs in the entire Croatian part of the Pannonian Basin System. In the first phase, modelling was based on results of laboratory testing on the core samples. It considered applying analogies with world-known projects of CO₂ subsurface storage and its usage to enhance hydrocarbon production. In the second phase, reservoir variables were analysed by variograms and subsequently mapped in order to reach lithological heterogeneities and to determine reliable average values of reservoir volumes. Data on porosity, depth and reservoir thickness for the “Gamma 3” and the “Gamma 4” reservoirs, are mapped by the ordinary kriging technique. Calculated volume of CO₂ expressed at standard condition which can be injected in the main reservoirs of the Ivani? Field at near miscible conditions is above 15.5 billion m³.     

Dawsonite fixation of mantle CO2 in the cretaceous Songliao Basin,Northeast China: a natural analogue for CO2 mineral trapping in oilfields

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.