Potential assessment of methane and heat production from geopressured–geothermal aquifers
© The Author(s) 2016
Published: 18 November 2016
Geopressured–geothermal aquifers of the US Gulf Coast contain a significant amount of geothermal energy and dissolved methane. This study investigates the effect of brine reinjection on the production of heat and methane from these aquifers. First, the range of uncertainty of aquifer properties was inspected to build the reservoir model of typical aquifers. A sensitivity analysis was then performed to find favorable conditions for production with and without reinjection, and the economic criteria for both scenarios were defined. This study concludes that reinjection has several advantages, such as increasing the sustainability of production, reducing reservoir connectivity risk, and disposing of produced brine in the same formation.
Formations of abnormally high pressure and temperature lie along the Gulf Coast of the United States at depths exceeding 3000 m. The brine of these formations holds a vast amount of geothermal energy and dissolved methane. Several studies have been conducted related to the development of these geopressured–geothermal reservoirs as an energy resource for both heat recovery and natural gas (Ganjdanesh et al. 2014; Plaksina and White 2016).
During the 1970s and 1980s, the US Department of Energy (DOE) began an organized program to evaluate the production of energy from geopressured wells (Griggs 2005). The goal of the project was to provide the information necessary to assess production characteristics of geopressured–geothermal reservoirs and their economic potential. The project had two aspects: Wells of Opportunity and Design Wells (Garg et al. 1986; Klauzinski 1981; Riney 1992, 1988; Swanson et al. 1986). In the Wells of Opportunity program, several deep abandoned exploration wells in geopressured zones were recompleted and tested. In the Design Wells program, several wells were designed and drilled specifically as geopressured wells. The models in our study were built based on the results from the DOE study.
Estimates by different investigators of dissolved natural gas in geopressured sandstones in the Gulf of Mexico cover a wide range. The Hise (1976) estimate of the in-place natural gas was 85 trillion standard cubic meter (sm3), while the Jones (1976) estimate was 1300 trillion sm3. Wrighton et al. (1981) estimated that the geopressured–geothermal resource of the northern Gulf of Mexico could exceed 28 trillion sm3 of recoverable natural gas. These estimates are based on different assumptions concerning the thickness of the formations, their areal extent, and the degree to which the formation is saturated with methane. These numbers are significant and several times bigger than conventional natural gas resources. However, the recovery factor was estimated to be less than 3% (Wallace et al. 1979). (Recovery factor is defined as the produced percentage of in situ gas.)
The other available source of energy from deep saline aquifers is geothermal energy. Knapp et al. (1977) expressed that the temperature gradient in the hydrostatic pressured sediments of the Gulf Coast is about 2.7 °C/100 m. In the geopressured zones, this gradient exceeds over 5.5 °C/100 m. Temperature at the depth of 3000 m ranges from 105 to 150 °C and below 4500 m, it exceeds 150 °C.
Esposito and Augustine (2011) investigated energy resources from the fairways of the Frio and Wilcox Formations of the Texas Gulf Coast using available data from the studies of the Bureau of Economic Geology (BEG) at the University of Texas at Austin (Bebout et al. 1978, 1982). Their estimate of methane-in-place for Frio and Wilcox was about 23 and 47 trillion sm3, respectively. In another study, Esposito and Augustine (2012) investigated the geopressured–geothermal formations of Texas and Louisiana. Five major geopressured–geothermal formations have been identified in Texas: lower Frio, Vicksburg–Jackson, lower Claiborne, upper Claiborne, and lower Wilcox. They concluded that the southern Vicksburg–Jackson has the highest quality geothermal resources because of thick sandstone and high temperatures.
Matthews (1981) proposed several methods for enhancing the gas production from geopressured aquifers including depletion to low pressure, pressure maintenance by reinjection of the produced brine, and formation of a gas cap by encouraging the vertical gas segregation. Ganjdanesh (2014) discussed that formation of a gas cap is not achievable because of small saturations of the liberated gas. Carbon dioxide injection into geopressured–geothermal aquifers has been introduced as a strategy to enhance energy recovery and store CO2 simultaneously. Ganjdanesh et al. (2015) proposed that CO2 can be injected in supercritical condition or co-injected with produced brine. Injected CO2 improves energy recovery by mobilizing methane (Hosseini et al. 2012), while the produced geothermal energy and methane can offset the cost of capture and storage. Recently, several studies have focused on coupled CO2 injection and brine extraction for geothermal energy recovery and enhancement of CO2 storage capacity (Hosseini and Nicot 2012; Liu et al. 2015; Salimi and Wolf 2012; Zhang et al. 2014).
Natural gas dissolved in brine has been an important energy source in Japan (Manrique and Kaneko 2000). This gas is produced from shallow aquifers formed from sandstone and siltstone, usually found at depths of 500–1000 m. It is also estimated that water-soluble gas in geopressured–geothermal aquifers of China can be a substantial unconventional gas resource (Liu et al. 2015).
This study utilized the findings of the DOE project to estimate the amount of producible energy from geopressured–geothermal aquifers of the Texas Gulf Coast. First, a simulation model of the aquifer was developed based on the Frio Formation of the Texas Gulf Coast. Then, a systematic investigation was conducted to determine the range of favorable conditions and to explore the best strategy for the coupled production of geothermal energy and natural gas. The range of conditions for sensitivity analysis was selected from the main geopressured–geothermal formations within the Texas Gulf Coast. The goal of this study is to determine whether brine reinjection is necessary for sustainable production of water and natural gas from geopressured–geothermal aquifers.
The first step of this study was to analyze the uncertainty of variables involved in the modeling of energy production from geopressured–geothermal aquifers. We investigated parameters related to reservoir size and quality, fluid properties, well productivity, and development scenarios to find out their range of variation and their effect on energy production. We used available data from the DOE program to assess the importance of the different variables.
Initial conditions of fluid at 150 °C, 76 MPa, and 105,000 ppm
Methane mole %
Brine mole %
Bubble point 33.06 MPa
Bubble point 55.56 MPa
Gas saturation 2.5%
Gas saturation 5.0%
Component properties tuned for 150 °C, 76 MPa, and 105,000 ppm
Critical pressure, atm
Critical temperature, K
Critical volume, m3/k-mole
Molecular wt., g/g-mole
Volume shift (at reservoir conditions)
Volume shift (at surface conditions)
Critical volume (viscosity), m3/k-mole
Binary interaction coefficient corresponding to H2O
Flow behavior of gas at low saturation in Gulf Coast geopressured brine is a critical question. Free gas is released from brine inside the aquifer by decreasing pressure below the bubble point pressure caused by brine production. As gas bubbles continue to grow, they will eventually link up throughout the pore structure of the reservoir rock. The saturation at which this link-up occurs—critical gas saturation—depends on pore size distribution. If gas saturation builds up to a level higher than that at which a continuous gas phase is formed, gas will begin to flow. Critical gas saturation is always equal to or larger than initial gas saturation, except in gas caps (Holtz 2002; Martin 1979; Matthews 1981).
Some geopressured aquifers may initially contain some free gases, which exist when the gas saturation is below the critical gas saturation. Critical gas saturation is an important parameter in relative permeability data for production of mobile gas. It is generally assumed that critical gas saturation is about 2–5% and depends on the porosity and permeability of the reservoir rock (Matthews 1981). This study focuses only on dissolved gas or initial immobile gas; it does not examine gas caps.
Parameters used in Corey’s relative permeability function
Gas end-point relative permeability
Water end-point relative permeability
Critical gas saturation
Connate gas saturation
Maximum trapped gas saturation
Irreducible water saturation
Gas-relative permeability exponent
Water-relative permeability exponent
Since methane exsolution occurs as a result of pressure drop, a counter-current flow of gas and brine might happen in the vertical direction. Hence, hysteresis modeling for imbibition is necessary. The Holtz equation predicts that maximum trapped gas saturation is 0.345. Figure 6 shows several gas-imbibition relative permeability curves calculated by Killough (1976) and modified Land’s equation for modeling the hysteresis effect.
Area and average thickness of geopressured aquifers located at the Texas Gulf Coast
Sandstone thickness, m
Quality of the reservoir sandstone
The most important parameter indicating reservoir capability for fluid flow is permeability. Permeability of reservoir rocks in geopressured zones varies from 1 mD for very low-quality shaly sandstone to several 100 mD for high-quality sandstone. Many regions of geopressured aquifers contain low-permeability sandstone as a result of diagenesis caused by high temperatures. Rocks with permeability on the order of 10–20 mD are considered to be of marginal quality (Loucks et al. 1986). Rocks with permeability higher than 20 mD are considered to be of good quality. This sandstone quality exists only in some regions of the Frio and Wilcox Formations. The quality of sandstone at the Vicksburg–Jackson Formation is low because of very high depths and temperatures, which result in diagenesis and loss of permeability (Loucks et al. 1986).
We studied the process of gas evolution from high-pressure brine as pressure declines and asked questions about development scenarios, including: (1) Is it possible to drop reservoir pressure to a very low value so that huge volumes of gas evolve from the brine and flow toward the well? (2) Is it practical to perform pressure maintenance similar to conventional oil and gas reservoirs by reinjection of the produced brine?
The most important issue in the production of energy from aquifers is the necessity of reinjection of produced brine into the same aquifer, which provides pressure maintenance that leads to much higher energy recovery and resolves the issue of disposing of produced brine. The disadvantage of reinjection is the amount of required energy for pumping the reinjected brine in comparison with the amount of produced energy. Two important questions about the reinjection strategy are the rate and start time of injection.
Tubing inner and outer diameter and wellbore radius
Tubing OD (in)
Tubing ID (in)
Wellbore radius (m)
Several other factors affect the production of energy from geopressured–geothermal aquifers. Heterogeneity, fault-block shape, wellbore flow, salts other than NaCl, and gases other than methane are assumed to be second-order effects with respect to the production of energy from aquifers.
Parameters of the aquifer model in base-case study
Length and width, m
Number of grid blocks
100 × 100 × 40
Grid block size, m
16 × 16 × 3
Depth at top of formation, m
Initial pressure, MPa
Initial CH4 concentration, mole %
Initial brine concentration, mole %
k v/k h, −
Initial CH4 in place, million sm3
Initial brine in place, million sm3
Solution gas–water ratio, m3/m3
Total pore volume, billion rm3
CMG–GEM (2015) software, a general equation-of-state compositional simulator, was used in this study. The GEM wellbore model was used to relate wellhead and bottomhole pressures, and the thermal option was used to calculate temperature variation in the aquifer as a result of injecting cold water. The wellbore radius is 0.0756 m. The maximum liquid-production rate is 4000 sm3/day (standard cubic meter per day). It is assumed that the wellhead pressure of the producer should not drop below 1.7 MPa to keep a pressure high enough to allow fluid flow to the surface. After a period of time, wellhead pressure drops to 1.7 MPa. Then, the constraint of the maximum liquid-production rate automatically switches to minimum wellhead pressure and the production rate begins to drop until production ceases.
This simulation results for two development scenarios: (1) dropping reservoir pressure to a very low value so that huge volumes of gas evolve from brine and flow toward the well, and (2) performing pressure maintenance similar to that of conventional oil and gas reservoirs by reinjection of the produced brine.
Scenario 1: depletion to low pressure
Simulation results for strategy 1—depletion to low pressure
Maximum brine production rate, sm3/day
Minimum wellhead pressure of producer, MPa
Tubing ID, m
Production period, year
Injection period, year
Cumulative produced brine, million sm3
Cumulative produced gas, million sm3
Average produced gas–water ratio, m3/m3
CH4 recovery, %
aBrine recovery, %
Figure 9 shows that the reservoir can only hold the maximum production rate for less than 4 years, at which time the producer wellhead pressure drops to 1.7 MPa. The well constraint is switched to constant wellhead pressure, and the flow rate begins to drop gradually. At the end of a 20-year period, the flow rate is less than 2 sm3 per day.
Scenario 2: pressure maintenance
Injection and production summary for strategy 2—pressure maintenance strategy
Maximum brine production rate, sm3/day
Minimum wellhead pressure of producer, MPa
Minimum wellhead pressure of producer at start of reinjection, MPa
Maximum brine injection rate, sm3/day
Maximum wellhead pressure of injector, MPa
Temperature of reinjected brine, °C
Tubing ID, inch
Production period, year
Injection period, year
Cumulative produced brine, million sm3
Cumulative produced gas, million sm3
Average produced gas–water ratio, m3/m3
Cumulative injected brine, million sm3
CH4 recovery, %
Brine recovery, %
Scaling is one of the problems caused by temperature and pressure drop in aquifer, wellbore, and surface facilities (Abouie 2015). A decline in injectivity as a result of precipitation in the formation and clogging of the wellbore and surface facilities is considered a key technical and economic issue. Several water treatment techniques and inhibitors have been developed to help control the chemical balance and prevent scale precipitation (Crabtree et al. 1999).
Comparison of strategies
Results show that the pressure maintenance strategy has the advantage of keeping brine and gas production rates constant during the 20-year period. Hence, the energy recovery factor is much higher compared to that of the depletion case. Also, the recovery factor is almost 10%, indicating the presence of significant amounts of energy still in place at the end of the 20-year period. Thus, we conclude that the pressure maintenance scenario requires a much smaller aquifer size compared to that of the aquifer depletion case.
Energy balance analysis for both production strategies
Disposal (no injection)
Net methane work (Joule)
+0.793E + 15
+2.635E + 15
Net geothermal work (Joule)
+0.468E + 15
+1.604E + 15
Pump work (Joule)
−0.036E + 15
−0.637E + 15
Net generated work (Joule)
+1.225E + 15
+3.602E + 15
Average net power in 20 year (MW)
Results of energy calculations in Table 9 show that the pump work for reinjecting produced brine into the same aquifer is much higher compared to the pump work for disposal into a shallow aquifer. However, the net generated work from the reinjection strategy is also much higher, about three times larger than the net generated work from the no-injection strategy.
The decline curves of the two production strategies exhibit different characteristics. The main production mechanisms of the no-injection case are fluid and rock expansion, while the main production mechanism of the reinjection case is pressure maintenance. Therefore, a much larger drainage area is needed for the no-injection scenario to keep the production rate constant over a 20-year production period.
Samples of parameters in sensitivity analysis
Reinjection ratio, %
Skin factor, −
Tubing ID, m
It is not feasible to perform simulations over the whole parameter space. Therefore, a sampling method is used to select a subset of the whole parameter space. A set of job patterns generated by sampling method is called a design. A good design with favorable characteristics can be used to fit an accurate proxy model and draw reliable conclusions regarding parameter effects. The collection of job patterns (computational experiments) should be a representative subset of all possible job patterns.
In this study, first the “one-parameter-at-a-time” method is used to draw preliminary conclusions, which help to shrink the parameter space significantly. In this method, one of the parameters is varied over the range of samples, and all other parameters are fixed at a base-case condition. This procedure was performed for all parameters. The strategy of brine reinjection for pressure maintenance was selected for the base-case model. It is assumed that the maximum brine production rate is 4000 sm3/day and that the wellhead pressure of the injector is limited to 31 MPa. Cumulative produced brine and cumulative produced gas were chosen as objective functions.
The largest increase in water production occurs when permeability increases from 2 to 10 mD. The production is not sensitive to permeability above 20 mD. Permeabilities less than 10 mD are considered as poor quality. Permeabilities between 10 and 20 mD are considered as marginal quality. Permeabilities higher than 20 mD are considered as good quality.
The relationship between the change in skin effect of wellbore and the change in production is almost linear.
When decreasing the tubing ID below 0.1214 m, a significant drop in production rate occurred.
Summary and conclusions
Reservoir volume is the governing factor in production by depletion. A very small percentage of immobile gas can be produced by reservoir depletion. Production of gas evolved by depletion of the formation is not practical without using artificial lift. Artificial lift for production of huge rates at high depths is not economically feasible.
The product of thickness and permeability (k × h) is the governing factor in production by reinjection. Pressure maintenance has the advantage of keeping brine and gas production rates constant during the 20-year period. The pressure maintenance scenario requires a much smaller aquifer size compared to that of the depletion case. The energy recovery factor for the pressure maintenance case is much higher compared to that of the depletion case. Reinjection has several advantages, such as increasing the sustainability of production, disposal of produced brine in the same formation, and better energy balance.
Both authors contributed to discussions according to their respective areas of expertise and experience to the interpretation of data and development of the basic concepts and assumptions which constitute the reservoir model. RG set up the numerical model, conducted and interpreted numerical simulations, and drafted the manuscript. SAH contributed to the geological model, numerical simulations, and drafting of the manuscript. Both authors read and approved the final manuscript.
We would like to thank CMG for the educational license of their software that was used in this study.
The authors declare that they have no competing interests.
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