Modeling coupled convection and carbon dioxide injection for improved heat harvesting in geopressured geothermal reservoirs
© Plaksina and White. 2016
Received: 13 July 2015
Accepted: 7 January 2016
Published: 21 January 2016
Geopressured geothermal saline aquifers are an abundant low-enthalpy geothermal energy resource available in many coastal regions including the US Gulf of Mexico. In such geographic areas thick geopressured sandstones (up to several hundred meters thick) hold tremendous geothermal heat with conservative estimates of gross extractable energy approximately 0.2 EJ per cubic kilometer of the formation. Additionally, widespread geopressure in sedimentary deposits of the Gulf region preserves favorable petrophysical properties of unconsolidated sandstones such as high porosity and permeability, thus, enhancing productivity and economics of potential heat harvesting projects. In this study we investigate the potential of a typical geopressured reservoir in the US Gulf coast to deliver commercial quantities of geothermal heat with the possibility of simultaneous supercritical CO2 sequestration into the same formation. Specifically, we focus on numerical simulation study of heat extraction from a model based on the Camerina A sand of South Louisiana. In our numerical experiments, we consider both theoretical and practical implications of combining a traditional heat harvesting method with supercritical CO2 injection. Moreover, this study pays specific attention to the effect of natural convection due to the formation’s tilt and uneven heating at the reservoir boundaries and its impact on the forced convection due to geofluid withdrawal. The numerical simulation results suggest that introduction of supercritical CO2 might have an observable positive effect on the ultimate heat recovery and that a strategic injection/production well placement might further enhance density-driven flows inside the geothermal formation.
KeywordsGeothermal energy Geopressured brines Saline aquifers Natural convection Forced convection Carbon dioxide sequestration TOUGH2
Geothermal systems hold abundant and carbon-free thermal energy for potential electricity generation, space heating, and air-conditioning. For example, the subsurface potential of the US contains approximately 170,000 EJ (1 EJ = 1018 J) of energy (MIT 2006). One such energy source readily available in many coastal regions across the globe is geopressured saline sedimentary aquifers. Geopressured aquifers are usually undercompacted, brine saturated, porous, and permeable sandstone formations that have anomalously high pore pressures and reservoir temperatures over 100 °C. Among all geothermal systems, geopressured fields are considered a medium- and low-grade (or low-enthalpy) geothermal resource that occupies large subsurface areas in coastal regions (Esposito and Augustine 2011). The US states of Louisiana and Texas are examples of geographic locations where geopressured systems occur frequently and occupy the areal extent of more than 145,000 km2 (MIT 2006).
Several technical obstacles may render development of most coastal geopressured systems sub-commercial. These low-enthalpy systems require drilling multiple injection wells for improved heat sweep because they have lower heat content and thermal efficiency. Costly pressure maintenance programs and surface handling of withdrawn geofluids may make these reservoirs unattractive for commercial development (Freifeld et al. 2013). In addition to these problems, withdrawal of geothermal fluids might cause land subsidence due to compaction in the producing geologic formation unless the produced geofluid is re-injected into the reservoir or shallower formations (Gustavson and Kreitler 1979). As a result, pilot commercial projects exploit only those sites that have anomalously high geothermal gradients and strong water drives—the so-called “low-hanging fruit” of the tremendous resource.
In deep sedimentary basin geothermal production techniques are usually divided into two main categories: coproduced fluids and geopressured geothermal extraction. The first development strategy uses thermal energy of hot water coproduced with oil and gas. This type of geothermal resource is confined to existing hydrocarbon fields at depths between 4 and 6 km (MIT 2006). In the US, the annual volume for coproduced hot water is approximately 33 billion barrels which is equivalent to 3000 MW based on geofluid temperature of 100 °C (Curtice and Dalrymple 2004). Geothermal projects of the second category, geopressured brines, are independent from oil and gas production and develop thermal potential of deeply buried aquifers. According to the latest conservative estimates, the Northern Gulf of Mexico (GOM) basin stores raw thermal energy of about 46,000 EJ (White and Williams 1975).
Although coproduced and independent geothermal reservoirs seem to be very similar for modeling purposes, their initial states (and thus, model initialization methods) differ. This research demonstrates benefits of initializing numerical models as quiescent systems with a proper temperature distribution (quiescent period is a period during which the reservoir experiences no injection or production, and it might range from 100 to millions of years). The thermal profile of coproduced geothermal reservoirs, however, is distorted by oil and gas production, and initialization with the quiescent period would not provide the correct temperature distribution for a coproduced project. This study focuses on geopressured brines, and therefore, we assume no forced convection (due to injection or withdrawal of geofluid) prior to heat harvesting.
Despite the fact that geothermal heat extraction is still considered a marginally profitable energy industry, a number of scientists have already proposed several strategies to make geothermal projects more economically attractive. More specifically, Ganjdanesh et al. (2015) have investigated how the energy cost could be reduced with capturing and storing CO2 inside the geothermal formation. National agencies such as the US Geological Survey (USGS) and Department of Energy (DoE) also propose favorable conditions and location for such project that include vast subsurface areas of the GOM (Warwick et al. 2014; Goodman et al. 2011; Nicot 2008). Several prominent studies have proposed to utilize sequestered CO2 as a secondary fluid to deliver the heat from reservoir’s hot lower boundary (Randolph and Saar 2011; Salimi and Wolf 2012; Randolph et al. 2013; Adams et al. 2014). This interest in using CO2 in geothermal projects stimulated further research on the behavior of the supercritical greenhouse gas in the subsurface conditions. In this context, for our investigation the most interesting works on CO2 behavior in geologic formations include the numerical study of CO2 flow under non-isothermal conditions by Singh et al. (2011), the investigation of supercritical CO2 injection into a deep saline aquifer by Vilarrasa et al. (2013), and the study of the dynamics inside the CO2 geologic storage by Pool et al. (2013). All these works provide a solid foundation and expectation of how supercritical CO2 plume should behave inside a geothermal system.
This study builds on this foundation and offers an investigation of a new method for improved heat recovery from low-enthalpy geopressured aquifers by combining the effects of natural and forced convection and density-driven effects of CO2 injection. Particularly, we demonstrate the advantages of characterizing a natural convection pattern inside a tilted or flat geothermal formation that might help place injection/production wells strategically to enhance subsequent heat extraction by the coupled convection. This approach allows for better geothermal resource estimation, potentially improved economics and a selection of a more efficient production arrangement. Because the current study might be particularly beneficial to the US GOM region, in our numerical experiments we use models with petrophysical and thermodynamic properties of typical GOM geopressured formations. Additionally, this study discusses heat harvesting simultaneous with small scale CO2 sequestration, the way to avoid land subsidence with re-injection of the produced geofluid into the same formation and the effect of the formation dip on the ultimate heat recovery. One South Louisiana aquifer, the Camerina A, is a central example for this study used for a more detailed investigation of an optimal geothermal production scenario.
Although the economic feasibility evaluation is not a part of this study, because of constant changes in the carbon tax agenda, high volatility on energy markets, and varying abilities to fund renewable projects, we can outline a possible life cycle of such geothermal reservoir for engineering and energy production purposes. A geopressured reservoir could be brought down to pressure suitable for economic injection of the supercritical gas (like in the case of Camerina reservoir the upper portion of which has been depleted during oil production). However, to prevent quick subsidence of mostly unconsolidated sediments, the geofluid must be re-injected into the shallower layers. At this stage of the production cycle both thermal and dynamic energy can be used for electricity generation purposes. Once overpressure is depleted, the project can be categorized as a carbon dioxide sequestration project and corresponding financial benefits can be applied to offset high compression costs. However, at this point in the life cycle all withdrawn geofluids must be returned into the formation after heat harvesting to maintain reservoir pressure and help mixing the supercritical gas with the brine. In addition to creating density-driven convection, this mixing is important in controlling the gas plume and ensure caprock integrity as discussed later (Islam et al. 2013; Shukla et al. 2010; Karimnezhad et al. 2014; Wang et al. 2015).
In this section we introduce necessary theoretical background on convection in flat and tilted porous media which are analogous to brine saturated sandstone geothermal reservoirs used in this study as well as describe the numerical simulation model used to obtain thermal energy production data. Additionally, we provide the description of the model initialization process and the design of experiment that helps identify the most significant parameters affecting the energy output.
Convection in flat and inclined porous media
In Eq. 1, γ is the thermal expansivity of the fluid, ρ is fluid’s density, k is permeability of the porous medium, g is the acceleration due gravity, c is fluid’s specific heat, h is the height of the system’s square cross-section, ΔT is a change in temperature, μ is the fluid’s viscosity, and K is the average thermal conductivity of the fluid and the rock matrix. The value of the Rayleigh number indicates if conditions favorable for convection have been reached. Specifically, when Ra exceeds 4π2 due to non-uniform heating and/or compositional heterogeneities (for instance, changes caused by mixing with gas or salt), the investigated system becomes unstable and convection cells begin to form (the critical value of 4π2 is derived from a solution for a system with an infinite horizontal dimensions, uniform petrophysical properties, and constant top and bottom temperatures (Nield and Bejan 2006)). Based on the same study, a typical fluid density change in naturally convecting systems is about one percent.
Although convection in flat systems is of interest in some development cases as highlighted in Zhang et al. (2014), in the GOM region many hot saline aquifers are dipping. Dip in such geologic formations can be local or sustained for the entire length of the reservoir. Tilted geopressured formations are particularly common around salt structures that cause deformation of adjacent sand deposits as well as their anomalously high temperature. The base case of this study, the Camerina A sand, is a dipping system due to its proximity to the Gueydan salt dome (Smith and Reeve 1970). Therefore, a more careful examination of natural convection in inclined reservoirs is needed.
Simulation model and setup of numerical experiments
The Northern GOM basin is a prolific geopressured geothermal province with many thick sandstone saline aquifers. To build a realistic numerical model for subsequent flow simulations, we use the properties of a hot saline aquifer in the GOM coast of Louisiana suitable for heat extraction. The Camerina A sand of South Louisiana is selected as a prototype for the simulation model (Plaksina 2011; Gray 2010).
Reservoir properties for 2D simulation runs
3.45 × 107
Initial average temperature
2.0 × 10−8
Injection water enthalpy
3.0 × 105
Wet rock heat conductivity
Reservoir width for 2D run
Although surface facilities and energy conversion is not in the scope of this study, it is important to note that the Camerina A sand is located in a geographic area where relatively low geothermal gradients are expected. Thus, one of possible methods to convert the heat energy of the aquifer’s fluid into electricity is an organic binary cycle for electricity generation (MIT 2006).
Model initialization and design of experiments
To see the benefits of initializing geomodels with proper geothermal gradient and running the quiescent period, a number of 2D simulations were performed with varying geometries and petrophysical properties (Pruess et al. 1999). Because one of the objectives of this study is to find parameters that influence heat recovery the most, a factorial design was used to vary the factors of interest, and for each case the Rayleigh number and its critical value were calculated (tabulated in Additional file 1: Appendix B). To encompass a wide range of geometric and petrophysical properties found in the Northern GOM basin, two levels of permeability (100 and 1000 md) and thickness (100 and 200 m), and three levels of dip (0, 2 and 15°) were used in the design of experiments (Ewing et al. 1984).
The formation pressure and geothermal gradient (Table 1) are lower than they would be expected in the geopressured zone in the GOM coast. Gray (2010) suggests that the Camerina A sand, which is a typical sand deposit in the zone, has a geothermal gradient of 29 °C/km and initial formation pressure over 80 MPa. In our numerical investigation, however, the value of the initial formation pressure is lowered for two reasons. First, the solutions obtained with the equation of state (EWASG) in the simulator of choice (TOUGH2) become less stable and reliable at high pressures. To our knowledge, this numerical problem has not been solved to date, thus, these extreme pressure conditions are still out of numerical reach even though the researchers are on track to address this problem for extra deep reservoirs (Zhang et al. 2011). Because of this gap in current numerical tools, we decided to resort to a common in such situation approach and work in the range of pressures that provide reliable solutions. Nevertheless, we emphasize that the actual reservoirs of such temperatures and pressures are found much deeper. Second, we conduct a comparative study of production cases with and without CO2 injection to analyze the effect of density-driven convection. To achieve this, it is instrumental to keep the numerical test conditions as similar as possible. However, at high initial pressures which become even higher, downdip simulation of CO2 injection with current software tools is impossible for reasonable injection pressure range. Thus, to compare energy output from the simulated systems in which only CO2 injection rate is varying (0 for no CO2 injection and 10−4 kg/s for the case with CO2 injection), the initial formation pressure is kept at 34.5 MPa. This pressure value was derived from the experiments with the simulator and the range of stability of the equation of state.
As for the land subsidence problem usually associated with geothermal development, we propose to re-inject the withdrawn geofluid into the same formation (in the case of extreme overpressure, however, injection into a shallower formation might be considered at the initial production stage). This strategy is common place for geothermal projects because it helps solve several problems. First, keeping net zero withdrawal prevents compaction of the unconsolidated sandstone and preserves favorable petrophysical properties. Second, cold water re-injection is an important component in setting the forced convection in motion and keeping the supercritical gas plume from rising toward the top of the reservoir. Final, re-injection of the geofluid back into the formation relieves some costs associated with surface handling of large volumes of geothermal fluids (MIT 2006).
Natural convection modeling
The ability to predict heat transport (such as conduction or convection) is valuable for successful production planning, but not sufficient for adequate geothermal resource estimation and developing an optimal production strategy. In addition to the Rayleigh number, the engineer needs to know the approximate shape of the natural convection pattern, the span of the quiescent period during which natural convection stabilizes, and the effect of the bounding layers on the reservoir’s temperature profile. This section provides the results of modeling these three aspects.
Geothermal production and CO2 injection modeling
Using the experimental design (Additional file 1: Appendix B), we generated three sets of simulations: (1) twelve geofluid production cases initialized without the proper geothermal gradient and quiescent period, (2) twelve geofluid production cases with natural convection in-place at the time of heat extraction, and (3) a set of twelve cases with simultaneous geofluid production and CO2 injection, initialized with natural convection. The response of interest for all simulation runs is energy extracted, E, after 10, 20, and 30 years of production. These results along with the factors are merged into one dataset and imported into statistical modeling software (R Team 2013).
To focus on the most important factors, the dataset is split into subsets by time (10, 20, 30 years) and flow rates (0.2, 2, 20 kg/s) and inspected for correlation. Correlations between energy outputs for 10 and 20 years of production and 20 and 30 years of production are 0.999 and 0.998, respectively. Correlations between subsets split by the production flow rate are 0.999 and 0.997 for 0.2–2 kg/s and 2–20 kg/s, respectively. Therefore, it is possible to reduce the number of factors by analyzing only one subset with energy output after 10 years of hot water production at a flow rate of 0.2 kg/s. All significant factors found for this subset are significant for the entire dataset.
Natural convection modeling in this study emphasizes the importance of the bounding layers and the quiescent period. Although the top and bottom bounding layers have the greatest effect on temperature profile in a quiescent system (due to the areal extent of these layers), it would be interesting to investigate the impact of side bounding layers in future research. One potential benefit of modeling a side bounding layer is the ability to incorporate a salt dome with its heat fluxes. However, introduction of additional bounding layers (or heat sources) will impact the duration of the quiescent period. Therefore, a more thorough analysis with a new experimental design might be necessary to establish the time span after which convection in such complex system becomes stable.
Can CO2 sequestration be done simultaneously with heat extraction, without impairing hear recovery? The simulation runs (Fig. 11) show that injection of small amounts of supercritical CO2 away from the geofluid producer and injector is beneficial. Because water displacement (or forced convection) is the dominant component in coupled convection (natural and forced), we conclude that increased energy output in the cases with CO2 injection is due to additional displacement rather than gas dissolution and subsequent density-driven convection. This conclusion, nevertheless, should not undermine further attempts to simultaneously harvest geothermal heat and sequester CO2 with higher injection rates at which the mentioned effects might become more pronounced. The sequestration rate could be increased to match those in major CO2 sequestration projects (NETL 2008). The choice of the low rate of 10−4 kg/s per meter of the horizontal well was dictated by the necessity to compare against the same production arrangements in different geologic systems (ten-fold difference in permeability, high and zero dips) and does not mean that the rate of 10−4 kg/s per meter of the horizontal well is the upper limit for each sedimentary geothermal aquifer. For 1000 md permeable and 200 m thick systems, the CO2 injection rate could have been much higher, but would cause rapid pressure buildup in lower permeability reservoirs (and may lead to stability problems in equation of state). Therefore, the next step in research is to determine whether aquifers with thermodynamic and petrophysical properties favorable for CO2 sequestration can also be prolific geothermal systems.
In this study, we conducted a numerical investigation of the effects of the coupled convection and CO2 injection on heat extraction from sedimentary geothermal aquifers. The analysis showed that there were certain benefits in characterizing natural convection pattern prior to heat harvesting, because the knowledge of the convection pattern allows to compare meaningfully alternative production designs. Statistical analysis of the simulation results confirmed the expectation that dip controlled the intensity of natural convection and aided forced convection at moderate production and injection rates. The juxtaposition between simulation suites with and without CO2 injection revealed that injection of the supercritical greenhouse gas had a positive impact on the ultimate thermal energy recovery.
CO2 sequestration at higher gas injection rates with simultaneous heat harvesting and dynamic control over the gas plume might further increase revenue. Because both CO2 sequestration and geothermal aquifer development are marginally profitable, this approach might make the combination project more commercially attractive.
A comparative study of alternative software tools might provide calibration of the obtained results and resolution for problems involving heat fluxes. In this study, the analysis of heat fluxes to the wellbore or in and out of the reservoir was used sparingly and qualitatively. The reason for this is limitations imposed by output from TOUGH2 software that does not separate conduction, convection, and radiation. It would be particularly helpful to have such capability for estimation of heat fluxes from bounding layers.
One can envision an investigation of effects of non-uniform salinity and heat sources due to the presence of salt domes on the natural convection pattern. Thermohaline convection is an important factor in heat transfer in the GOM coast environment that might have an impact on recovery of geothermal heat.
Professor Jeffrey Nunn and Tyler Gray (MS) of the Department of Geology and Geophysics, Louisiana State University, characterized the Camerina A reservoir, providing valuable data and guidance. Professor Jeffrey Hanor of the Department of Geology and Geophysics, Louisiana State University, advised on thermohaline flows in the Gulf of Mexico. Financial support for research assistant stipends, travel, training, and computing hardware was provided by the Chevron Distinguished Professorship in the College of Engineering, Louisiana State University. Additional support for purchase of software was provided by the Coast to Cosmos Focus Area at the Center for Computation and Technology, Louisiana State University.
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