Aquifer Reservoir Research Articles

The potential role of data-centres in enabling investment in geothermal energy

A techno-economic analysis is presented, of the potential for data-centres and fibre optic networks to drive investment in geothermal resources. The concept is attractive because of data-centres’ stable demand for electricity and refrigeration at a scale of <5MWe, corresponding to the output of a single well doublet; because the cost of establishing a fibre optic link is an order of magnitude less than augmenting an electricity transmission network; and because it offers an opportunity for geothermal systems to compete with the retail price of electricity. A comparison of energy delivery outcomes was performed for both engineered geothermal systems (EGS) and hot sedimentary aquifer (HSA) reservoirs to identify the minimum conditions that could make the concept economically attractive. For the high temperature EGS, a single and dual pressure binary organic Rankine cycle (EGS-ORC, EGS-2×ORC), a single stage flash (EGS-flash) and a hybrid flash-binary system (EGS-hybrid) were studied. The HSA system investigated the direct use (HSA-DU) of the geo-fluid in an absorption chiller for refrigeration and the use of coincidental natural gas resources to deliver electricity via an internal combustion engine. The technical performance of these systems was assessed for a range of well-head pressure (EGS only) and geo-fluid flow rate scenarios. The economic performance of the combined set of investments in optical fibre and energy infrastructure was examined by estimating the expected internal rate of return (E[IRR]). The HSA-DU option yielded an E[IRR] of 14%, following the installation of energy capacity equivalent to the output of one well-doublet assuming the displacement of the Australian retail price of electricity; and 12% for the US retail price. In comparison, the EGS-hybrid was found to have an E[IRR] of 8%, if the Australian retail price were displaced and 4% if the US retail price were displaced. The EGS-flash, ORC and 2×ORC scenarios were found to be progressively less attractive than the EGS-hybrid. To identify the conditions under which the concept could satisfy commercial hurdle rates, the sensitivity of the E[IRR] was investigated for the cost of an optical fibre link; the EGS resource depth; the retail price of electricity displaced; and a data-centres’ energy consumption profile. Credits for CO2 emissions abatement at $23/ton were found to have only a marginal influence on the economic performance of the EGS and HSA scenarios examined.

Hydrogeochemical modelling of fluid–rock interactions triggered by seawater injection into oil reservoirs: Case study Miller field (UK North Sea)

Abstract A hydrogeochemical model is presented and applied to quantitatively elucidate interdependent reactions among minerals and formation water–seawater mixtures at elevated levels of CO 2 partial pressure. These hydrogeochemical reactions (including scale formation) occur within reservoir aquifers and wells and are driven by seawater injection. The model relies on chemical equilibrium thermodynamics and reproduces the compositional development of the produced water (formation water–seawater mixtures) of the Miller field, UK North Sea. This composition of the produced water deviates from its calculated composition, which could result solely from mixing of both the end members (formation water and seawater). This indicates the effect of hydrogeochemical reactions leading to the formation and/or the dissolution of mineral phases. A fairly good match between the modelled and measured chemical composition of produced water indicates that hydrogeochemical interactions achieve near-equilibrium conditions within the residence time of formation water–seawater mixtures at reservoir conditions. Hence the model enables identification of minerals (including scale minerals), to quantitatively reproduce and to predict their dissolution and/or formation. The modelling results indicate that admixing of seawater into formation water triggers the precipitation of Sr–Barite solid solution, CaSO 4 phases and dolomite. In contrast, calcite and microcrystalline quartz are dissolved along the seawater flow path from the injection well towards the production well. Depending on the fraction of seawater admixed, interdependent reactions induce profound modifications to the aquifer mineral phase assemblage. At low levels of seawater admixture, Ba–Sr sulfate solid solution is precipitated and coupled to concurrent dissolution of calcite and microcrystalline quartz. Massive dissolution of calcite and the formation of CaSO 4 phases and dolomite are triggered by intense seawater admixture. Hydrogeochemical modelling to reproduce observed compositional trends, resulting from an increase of the seawater fraction, can help (1) to explain changing production properties and (2) to predict the type and the degree of scaling depending on the content of injected seawater.

Full-Field Heavy-Oil Conversion From Cold to Hot Production

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146695, ’Full-Field Heavy-Oil Conversion From Cold to Hot Production: Challenges and Solutions,’ by F.E. Jansen, SPE, A. Curtis, SPE, L.V. Mejia-Cana, J. Ramsdal, SPE, and J.O. Selboe, SPE, Statoil ASA, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed. With an increasing interest in extra-heavy-oil (EHO) extraction, several heavy-oil fields will be produced initially by a cold-production scheme, and, at a later stage, thermal production in the form of steam injection can be used to enhance the recovery. In an EHO cold-to-hot conversion scheme, several choices must be made with respect to well positioning, completion options, timing, and scale of the conversion. Introduction Challenges in establishing a good reservoir-management plan for EHO reservoirs over their entire life span stem from the complexity of modeling heavy-oil recovery, fine-grid requirements, very large models, and dedicated tools (i.e. thermal vs. conventional simulators). In this sense, crude oils can be divided roughly into three groups: those that flow without added heat (e.g., conventional oils), those that do not flow without added heat (bitumen), and those that will flow initially but yield a less-than-satisfying recovery with only cold flow (e.g., many EHO fields that are the focus of this paper). The challenge for reservoir-management optimization of EHO reservoirs is combining slow pressure propagation (low mobility), unfavorable mobility ratio to water, and the large area, thus requiring a very large number of wells to achieve good reservoir drainage and acceptable field-production rates. The environmental requirements regarding minimization of footprint and water handling, combined with possible conversion from cold to hot production, make the handling of wells even more complex. Cold Production If the in-situ viscosity is low enough to allow economical natural flow without added heating of the reservoir, primary cold production normally is preferred if the reservoir compressibility and aquifer support are high enough to deliver a reasonable recovery (often by use of horizontal wells, downhole diluent injection, pumps, and narrow well spacing to increase well rates and field recovery). In some cases, the reservoir and mobility relationship is appropriate for waterflooding. Several cold-production options exist: waterflooding, with or without polymer, and cold heavy-oil production with sand (CHOPS). However, full-life-cycle evaluations must be made because waterflood and CHOPS preclude subsequent hot-production conversion. Important for all of these techniques is the use of downhole pumps—hydraulic pumps, electrical submersible pumps, and progressing-cavity pumps (PCPs). The most common is the PCP because of its reliability and ability to handle high-viscosity fluid and sand. Diluent, in the form of light hydrocarbons, often is injected downhole (as deep into the well as possible) to reduce the effective viscosity in the well and flowlines. Diluent handling and possible regeneration can be important.

Assessing the monitorability of CO2 saturation in subsurface saline aquifers

We propose a method to assess the geophysical monitorability of petrophysical parameters (in this case CO2 saturation) in subsurface geological reservoirs. The approach is based on measuring and inverting up to six geophysical parameters: P- and S-wave impedances and quality factors (1/attenuation), density and electrical resistivity. We use Shannon's information measure to quantify the information obtained from the inversion of different combinations of geophysical parameters. We thus develop a generic approach to assess the joint monitorability of supercritical CO2 saturation when CO2 is stored in subsurface reservoirs. Uncertainty analysis shows that expected information is in general nonlinearly related to the level of a priori or measurement uncertainty in the geophysical and petrophysical parameters, to the true CO2 saturation, and also to the measurement frequency in the case of seismic measurements. Prior uncertainties in petrophysical parameters such as porosity have a significant effect on the monitorability, highlighting the need for accurate benchmark (pre-injection) measurements and reservoir characterization in the case of time-lapse (4D) monitoring. We show that estimates of P-wave seismic attenuation contribute most to the overall information obtained, and that in principle the joint application of different geophysical methods can significantly improve monitorability. We applied the approach to assess the monitorability of the CO2 saturation after 10 years of simulated injection into a saline aquifer reservoir in the near-shore UK North Sea. Application of the approach to design optimal data combinations for hydrocarbon saturation assessment and monitoring is straightforward.

Detectability of petrophysical properties of subsurface CO2-saturated aquifer reservoirs using surface geophysical methods

The process of capturing carbon dioxide ([Formula: see text]) and injecting it into deep saline aquifers is becoming an important method to reduce future atmospheric emissions of [Formula: see text]. Key challenges facing carbon capture and storage (CCS) are the storage reservoir's size and safety. The storage size can be addressed by focusing on large saline aquifer reservoirs. The safety concern may be lower if [Formula: see text] is injected into depleted hydrocarbon reservoirs because their cap-rock integrity is already proven, but such capping systems are generally potentially compromised by poorly cemented abandoned wells, and compared to saline aquifers, their storage size is small. Therefore, the long-term focus of CCS is on saline aquifers. To reduce the corresponding risks, comprehensive long-term monitoring is inevitable.

Modeling of CO2 Leakage up Through an Abandoned Well from Deep Saline Aquifer to Shallow Fresh Groundwaters

This article presents a numerical modeling application using the code TOUGHREACT of a leakage scenario occurring during a CO2 geological storage performed in the Jurassic Dogger formation in the Paris Basin. This geological formation has been intensively used for geothermal purposes and is now under consideration as a site for the French national program of reducing greenhouse gas emissions and CO2 geological storage. Albian sandstone, situated above the Dogger limestone is a major strategic potable water aquifer; the impacts of leaking CO2 due to potential integrity failure have, therefore, to be investigated. The present case–study illustrates both the capacity and the limitations of numerical tools to address such a critical issue. The physical and chemical processes simulated in this study have been restricted to: (i) supercritical CO2 injection and storage within the Dogger reservoir aquifer, (ii) CO2 upwards migration through the leakage zone represented as a 1D vertical porous medium to simulate the cement–rock formation interface in the abandoned well, and (iii) impacts on the Albian aquifer water quality in terms of chemical composition and the mineral phases representative of the porous rock by estimating fluid–rock interactions in both aquifers. Because of CPU time and memory constraints, approximation and simplification regarding the geometry of the geological structure, the mineralogical assemblages and the injection period (up to 5 years) have been applied to the system, resulting in limited analysis of the estimated impacts. The CO2 migration rate and the quantity of CO2 arriving as free gas and dissolving, firstly in the storage water and secondly in the water of the overlying aquifer, are calculated. CO2 dissolution into the Dogger aquifer induces a pH drop from about 7.3 to 4.9 limited by calcite dissolution buffering. Glauconite present in the Albian aquifer also dissolves, causing an increase of the silicon and aluminum in solution and triggering the precipitation of kaolinite and quartz around the intrusion point. A sensitivity analysis of the leakage rate according to the location of the leaky well and the variability of the petro-physical properties of the reservoir, the leaky well zone and the Albian aquifers is also provided.

Mathematical modeling of geomechanical behavior of tarmat during the depletion of giant oil reservoir-aquifer systems

In this work, deformation and failure behavior of tarmat layers during depletion of a giant reservoir–aquifer system has been studied. Deformation response of the tarmat to increasing pressure differential caused by continuous depletion of reservoir is examined and a mathematical model is developed for the study of this type of composite systems. The geomechanical failure that takes place when the pressure differential reaches a critical value is also evaluated, along with the characterization of the resulting fracture. Plate theory, maximum shear stress failure criterion, conventional well test model, Perkins–Kern–Nordgren (PKN) and Khristianovic–Geertsma–de Klerk (KGD) models and flow through fractures models are used. The developed sensitivity analysis proposes the proper protocol to be followed in order to undertake production design in such composite systems. The methodology presented in this paper, ultimately, predicts fracture width and fracture permeability that would be developed in a system with a tarmat layer having a certain thickness and a reservoir being produced at a certain production rate and total depletion time.

Approximate Engineering Solution for Predicting Groundwater Table Variation During Reservoir Drawdown on the Basis of the Boussinesq Equation

With reservoir drawdown, the groundwater table in the adjacent aquifer falls down correspondingly. It is useful to calculate the groundwater table variation as a function of time during reservoir drawdown for hydraulic and hydrological purposes. The Boussinesq equation with a moving boundary is applied to analyze the groundwater table variation in the unconfined aquifer during reservoir drawdown. This approach assumes a negligible seepage face. Because the moving boundary condition in the mathematical formulation precludes analytical solutions even for the linearized Boussinesq equation, we have transformed the Boussinesq equation into an advection–diffusion equation to address the negligible seepage face and the moving boundary condition. On the basis of the Laplace transformation, we yield an analytical solution of a fixed boundary problem, which is further simplified to upper and lower polynomial solutions for convenient practical use. The polynomial approximate solutions are satisfactorily compared with a number of numerical simulations of the nonlinear Boussinesq equation. The results indicate that the polynomial solutions match well with the numerical solution, but demonstrate that the replacement of the sloped reservoir–aquifer interface by a vertical interface may cause errors of up to 10% of the height of the reservoir drawdown in the prediction of the groundwater table location. On the basis of the polynomial solutions, a methodology is provided to determine the ratio of hydraulic conductivity to specific yield along with a chart for convenient practical use. The limitation of the present study is that the presented solution tends to underestimate the groundwater table with seepage face neglected for rapid drawdown, high specific yield, low hydraulic conductivity, or mildly sloped interface cases.

Managing the risk of CO2 leakage from deep saline aquifer reservoirs through the creation of a hydraulic barrier

A prerequisite to the wide deployment of CO2 geological storage at an industrial scale is demonstrating that potential risks can be efficiently managed, which includes deploying an adequate monitoring during the injection phase and having intervention plans ready in case of major irregularity. This paper considers the injection of CO2 into a saline formation linked to a shallower aquifer through a leaky pathway. Brine, possibly followed by CO2, may start migrating up through the leak if sufficient pressure builds-up in the storage reservoir. For some man-made leakages (e.g. abandoned well), and more importantly for most of the natural ones (e.g. faults, fractured zone), acting on the transfer itself (i.e. on the leaky pathway) is hardly feasible. Consequently, the corrective measure hereby investigated aims at countering the main driving force of the CO2 upwards migration which is the pressure build-up under the leak by injecting brine into the shallower aquifer, thus creating a hydraulic barrier. Results show that this can be an efficient way to stop a leakage in less than a year instead of letting it continue for hundreds of years, even with a low and decreasing flow rate. It may also be implemented as a preventive measure, while continuing storing CO2.

A response surface methodology to address uncertainties in cap rock failure assessment for CO 2 geological storage in deep aquifers

Cap rock failure assessment, either tensile fracturing or shear slip reactivation of pre-existing fault, is a key issue for preventing CO 2 leakage from deep aquifer reservoirs up to the surface. For an appropriate use in risk management, the uncertainties associated with such studies should be investigated. Nevertheless, uncertainty analysis requires multiple simulations and a direct use of conventional numerical approaches might be too computer time consuming. An alternative is to use conventional analytical models, but their assumptions appear to be too conservative. An intermediate approach is then proposed based on the response surface methodology, consisting in estimating the effective stress state after CO 2 injection as a linear combination of the most influential site properties based on a limited number of numerical simulations. The decision maker is provided with three levels of information: (1) the identification of the most important site properties; (2) an analytical model for a quick assessment of the maximal sustainable overpressure and (3) a simplified model to be used in a computationally intensive uncertainty analysis framework. This generic methodology is illustrated with the Paris Basin case using a large-scale hydromechanical model to assess cap rock failure in the injector zone.

Compressed Air Flow within Aquifer Reservoirs of CAES Plants

A model on the air flow within aquifer reservoirs of Compressed Air Energy Storage (CAES) plants was developed. The design of such CAES plants requires knowledge of the reservoir air pressure distribution during both the charging and discharging phases. Also, it must assure air/water interface stability to prevent water suction during discharge. An approximate analytical solution for the pressure variations within the anisotropic reservoir porous space was developed, subject to the Darcy equation and for conditions of partially penetrating wells. Sensitivity analyses were conducted to identify the dominant parameters affecting the well pressure and the critical flow rate (water suction threshold). It is demonstrated that water coning is a factor that could severely limit the discharge air flow rate. A significant diminishment of that limitation and reduction of the pressure fluctuation can be achieved by enlargement of the air layer height and discharge period. Likewise, aquifers with larger horizontal permeability impose less restrictive critical flows. A conclusion on the preferred screen length could not be merely drawn from technological considerations, but should also involve important economic aspects.

From 3D Seismic to 3D Reservoir Deterministic Model Thanks to Logging Data: the Case Study of a Near Surface Heterogeneous Aquifer

Different surface seismic surveys have been recorded on an experimental hydrogeological site that has been developed for several years near Poitiers (France). The paper shows how 3D seismic imaging can be used to describe the near-surface heterogeneous aquifer. The acquisition spread is designed to perform both 3D refraction and reflection seismic surveying. Refraction survey enables us to obtain a 3D image in depth of a low velocity superficial zone contrasting with the underlying water – bearing carbonates. Refraction survey shows the main orientations (N90 and N50) of fracture corridors. These two directions have been selected as the drilling azimuths of two deviated wells C3 and C4. Reflection survey enables us to generate a 3D seismic pseudo velocity block in depth. The 3D seismic pseudo velocity block shows the large heterogeneity of the aquifer reservoir in the horizontal and vertical planes, and confirms the main structural orientations (N90 and N50) identified by the refraction survey. The low velocity areas correspond to high hydraulic conductivity. In order to quantify the porosity of the different productive layers of the aquifer, the interval seismic velocities have been converted in resistivity. For that purpose, the empirical relationship between seismic velocity and true formation resistivity proposed by Faust (1953) [Geophysics 18, 271-288] has been used. The 3D resistivity block is converted in porosity, by using the Archie law (1942) [Petrol. Technol. 146, 54-62]. The 3D seismic pseudo porosity block allows us to identify three different water productive layers: an upper layer at 35-40 m depth, an intermediate layer at 85-87 m depth and a lower layer at 110-115 m. The intermediate layer is composed of bodies having a porosity larger than 30%. These bodies represent the most karstic part of the reservoir. The very high resolution seismic surveying has led to obtain a 3D porosity seismic block which represents a deterministic high resolution reservoir model. After further calibration, that reservoir model could be used for flow simulation.

An assessment of CO2 transportation cost from the power plants to geological formations suitable for storage in North Greece

Abstract The work aims at providing an initial estimation of CO 2 transportation cost by means of pipelines. CO 2 will be stored in geological formations in North Greece where the majority of the thermal power plants located. Particularly, it was examined the CO 2 storage in saline aquifers and oil reservoir. The scenarios were developed taking into consideration factors such as the potential storage period, CO 2 storage capacity of the geological media, the emissions. The transportation cost of CO 2 was estimated using the methodology proposed by the IEAGHG. The results show that the transportation cost varies from 0.39 $/tn CO 2 up to 0.45 $/tn CO 2 (0.08 $/tn/100Km to 0.26 $/ton/100 Km). Additionally, the CO 2 emissions that come from the fossil fueled power plants can be stored in the oil reservoir and saline aquifer of Prinos for 51 years while in saline aquifers of W. Thessaloniki and Pentalofos for 60 and 54 years respectively. Taking into account the abovementioned results, the recommended approach seems to be a quite attractive solution.

Malibogazi groundwater dam: an alternative model for semi-arid regions of Turkey to store and save groundwater

In central Turkey, there are serious groundwater quality problems in the main river valleys and plains, and even in the lower parts of the secondary basins due to the underlying evaporitic geological formations. Groundwater quality improves towards the upstreams in the alluvium aquifers in most secondary valleys; however, groundwater potential decreases as well due to the reduced basin area, areal extent and thickness of the aquifers. The Malibogazi valley is situated to some 100 km north of Ankara. The dam constructed in the narrowest section of the valley has an average storage coefficient of 0.2 and the total and active storage capacities of 110,000 and 55,000 m3, respectively. The 20-m-thick aquifer extends for 6–7 km till the dam site within valley with an average width of 50–70 m. It mostly comprises sandy–gravely alluvial deposits. Malibogazi groundwater dam is a valve-controlled gravity flow dam. When the valves are opened, the water from the aquifer reservoir flows by gravity through supply pipe to the main irrigation channel, but when the valves are closed the water is stored in the aquifer and groundwater level begins to rise. Average groundwater discharge was about 20 l/s in 2005–2006 irrigation period. In this period, groundwater levels were about 2 m higher compared to the groundwater levels in the same seasons before the construction of the groundwater dam. Because the dam is of gravity flow type, it means an important contribution to the farmers since the operation cost is quite low. Malibogazi groundwater dam represents one of the first experiences of Turkey in the field of groundwater storage. Although the dam has small storage capacity, it may be a model for Turkey from the viewpoints of investigation, construction, dam wall, intake facility and measurements etc.

Characterization of the Pliocene Gas Reservoir Aquifers for Predicting Subsidence on the Ravenna Coast

The Pliocene reservoirs of the North Adriatic have produced gas since 1972. Several studies using reservoir and geomechanical models have been undertaken to quantify the surface land subsidence that may be attributed to pressure depletion resulting from gas production. Subsidence may continue after production ceases, as water influx repressures the depleted gas reservoirs, reduces the aquifer pressure, and causes the subsidence bowl to expand. Therefore, characterization of the Pliocene aquifers and water influx functions is important for long-term prediction of subsidence. An aquifer model was developed by integrating geological/geophysical interpretations, petrophysical data, and pressure/production data to describe the limited water influx observed in these reservoirs. The mechanism restricting water influx in the Pliocene gas reservoirs was found to be a combination of low effective permeability to water in the presence of clays and trapped gas saturation. The final aquifer model, which was validated with field pressure data, was used to predict long-term pressure drop in the aquifer for subsidence predictions.

Finite Element Modeling of the Kızıldere Geothermal System, Turkey

The Kızıldere geothermal reservoir and adjacent aquifers in the Büyük Menderes Graben comprise an integrated hydrogeological system and are dominated by flow in fractures and distinct strata. To investigate the effects of production, a two-dimensional (areal) distributed parameter model, based on finite element approximation for a hot water-type geothermal reservoir, was used. The model simulates heat transport combined with the flow of water through an equivalent porous medium. Because of the large region being considered, at the scale of the application the equivalent porous medium concept is appropriate. The model parameters were calibrated using production data from 1984 to 1998. The response of the model to fluid extraction agrees to what has been observed in the field. Then various flow rates were evaluated using the model to determine the possible response of the reservoir to future exploitation. The model indicates that the existing wells are not sufficient to sustain a 20 MWe operation for 20 years.

Simulation Study of Acid Gas Injection Into an Aquifer

Abstract A series of simulation runs using a compositional simulator were conducted to determine the area of influence that results from injecting acid gas (H2S) for 30 years at 330 e3m3 into a 75 m thick high permeability sandstone aquifer. In this study, the three-phase (gas-oil-water) equilibrium calculation was used. Initially, a 5 Township by 5 Range grid model was used to determine the area of influence; subsequently, a smaller grid model 1 Township by 1 Range was used. Boundary producers were required to properly simulate an infinite aquifer. This study found that buoyancy and relative permeability, more than other parameters such as the perforation interval and the gas-water capillary pressure, affected the area of influence. A refined 75-layer model, one-metre thick, was constructed to check the gravity effect. The results of this refined layer model agree closely with a 13-layer model after 11 years of acid gas injection. A blowdown simulation was also conducted to determine the time to significant water inflow from perforations at the bottom of the zone. The effect of a 50 year shut-in after 30 years of injection was also simulated. Introduction The objective of the study was to understand the reservoir volume and the area of influence that would result from the injection of H2S into the Basal Sand aquifer of the Cambrian age Deadwood Formation. This was accomplished through the use of a compositional simulator (CMG's GEM). The Husky Lloydminster Upgrader (HLU) produces large amounts of acid gas: mainly H2S. The existing sulphur plant removes the sulphur from the H2S. Implementation of H2S disposal into the Deadwood Formation would initially reduce the load on the existing HLU sulphur plant, and ultimately it might be shut-in. Any future expansion of the HLU would not require an additional sulphur plant if acid gas disposal was proven to be effective. For safety reasons and regulatory requirements, it was required to know where the injected H2S would migrate to within the aquifer over time. The resulting area of influence would determine the penetrating wells and the mineral rights owners that might ultimately be affected by H2S injection. In this study, a commercial compositional simulator (CMG's GEM) was used as the model as it can take H2S water solubility into account. In the simulation results, the area of influence is defined as the area that has an H2S concentration greater than 0.00001 mole fraction. This value is based on the numerical accuracy of the simulation. The selected simulator was developed for oil-gas-water three-phase and multi-components usage. To simulate an H2S-water system, a small amount of methane (0.0005 gas saturation) was used as an oil phase for initialization. To distinguish the initial methane gas from H2S in the gas phase, all the gas saturation graphs used a minimum scale of 0.0005. Deadwood Aquifer Formation and Reservoir Model References (1) and (2) provide a detailed geological appraisal and a mineralogy study of the Cambrian Deadwood Formation Basal Sand.

3D Seismic Imaging of a Near-Surface Heterogeneous Aquifer: A Case Study

Different surface seismic surveys have been recorded on an experimental hydrogeological site that has been developed for several years near Poitiers (France). The paper shows how 3D seismic imaging can be used to describe the near-surface heterogeneous aquifer. The acquisition spread is designed to perform both 3D refraction and reflection seismic surveying. Refraction survey enables us to obtain a 3D image in depth of a low velocity superficial zone contrasting with the underlying water – bearing carbonates. Variogram analysis and geostatistical filtering allow to filter random and structured acquisition noise. Factorial kriging is used to filter the small scale structures (cubic structure with a range of 55 m and nugget) in order to make the large scale structures appear and to determine their orientation: a main orientation N90 and a secondary orientation N50. These two directions have been selected to implement two deviated wells C3 and C4. Reflection survey enables us to get a 3D seismic pseudo velocity block in depth. The vertical resolution is enhanced thanks to deconvolution after depth conversion. A Wiener filter, defined at a reference well C1 has been applied to the seismic traces to convert into velocity the amplitude sections. The results obtained are validated at four wells (MP6, MP5, M8, M9) in which acoustic data have been recorded. The 3D seismic pseudo velocity block shows the large heterogeneity of the aquifer reservoir in the horizontal and vertical planes, confirms the main structural orientations (N90 and N50) pointed out by refraction survey. At a given depth, the velocity distribution shows preferential connections between wells. As an example, well pumping tests and pressure interference confirm the hydrodynamic connection between wells M13 and M21 defined by a low velocity zone at 88 m depth.

Continuous active-source seismic monitoring of C O2 injection in a brine aquifer

Continuous crosswell seismic monitoring of a small-scale [Formula: see text] injection was accomplished with the development of a novel tubing-deployed piezoelectric borehole source. This piezotube source was deployed on the [Formula: see text] injection tubing, near the top of the saline aquifer reservoir at [Formula: see text] depth, and allowed acquisition of crosswell recordings at [Formula: see text] intervals during the multiday injection. The change in traveltime recorded at various depths in a nearby observation well allowed hour-by-hour monitoring of the growing [Formula: see text] plume via the induced seismic velocity change. Traveltime changes of [Formula: see text] (up to 8%) were observed, with no change seen at control sensors placed above the reservoir. The traveltime measurements indicate that the [Formula: see text] plume reached the top of the reservoir sand before reaching the observation well, where regular fluid sampling was occuring during the injection, thus providing information about the in situ buoyancy of [Formula: see text].

Functioning of a coastal karstic system with a submarine outlet, in southern Spain

A conceptual model of the functioning of a complex coastal karst aquifer in southern Spain is presented. The system has well developed conduits below sea level and is connected to the Mediterranean Sea. It discharges through two conduits 12 m below sea level, 20 km apart. The Moraig conduit is the main outlet; the discharge to the sea is brackish. The Toix conduit only discharges to the sea during heavy floods and lets in seawater the rest of the time. During the 1999–2000 hydrological year, both conduits were monitored by flowmeters and electrical conductivity-temperature probes. On the basis of the collected data, the hydrological relationship between the functioning of the system and the sea was characterised. The conceptual model assumes the existence of a huge reservoir called an “aquifer reservoir” which is supplied by (1) freshwater from rainfall and (2) seawater flowing into the Toix conduit. In addition, during heavy rainfall events, fast infiltration brings considerable amounts of freshwater into the Moraig conduit. This is typical of a “by-pass” mechanism. Salinity and flow rates were simulated with the use of a rainfall-discharge and a rainfall-salinity model. The simulation of flow and salinity time series can be used for water management purposes.