GEOTHERMAL RESERVOIR ENGINEERINGProf. Dr. Mahmut Parlaktuna

Middle East Technical UniveristyPetroleum and Natural Gas Engineering Department

06531 Ankaramahmut@metu.edu.tr

1. IntroductionAlthough the geothermal reservoir engineering is related to oil and natural gas reservoir engineering principles, which was developed after 1930’s, the use of these principles in geothermal reservoirs was started at the end of 1960’s (Whiting and Ramey (1969), and Ramey (1970)).

Geothermal reservoir engineering starts with the determination of well locations and continues with several measurements within the wellbore (well logging, production rates, etc.), interpretation of these data, determination of production mechanisms and performance prediction studies of reservoir behavior. The ultimate goal of these studies is to determine the optimum production conditions to maximize the recovery of heat from the reservoir under suitable economic conditions.

According to Ramey (1977) the main activity of a reservoir engineer is the prediction of the long-term behavior of the wellbore and/or reservoir under study. In this context, the important questions to be answered are:

1. What is the most suitable development plan of the reservoir?

2. How many wellbores should be drilled to reach the most suitable development plan? What would be the well pattern?

3. What will be the production rates of the wellbores?

4. How much heat will be recovered?

5. How will the change in reservoir temperature be?

6. Will there be a need to apply enhanced recovery techniques to increase the heat recovery from the reservoir?

In order to find answers to those questions, reservoir engineer must pursue a continuous study with a great care from the beginning of production. Reservoir engineer can have a chance to revise his/her studies and a better representation of the reservoir with the addition of new data during production. Unfortunately, the best information about the reservoir is generally being available at the latest stage of production from the reservoir.

Reservoir engineer must define physical processes of a geothermal system. This can be achieved in three steps:

1. First of all the physical processes that are related to the geothermal system must be defined. Those processes should be used to develop the conceptual model of the reservoir.

2. Secondly, physical and chemical properties of reservoir rock and fluid must be determined.

3. Lastly, mathematical and physical models of the reservoir must be developed with the help of existing data. This model must consist the initial and boundary conditions of the

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reservoir. The model must be refined with the addition of new data as production continues. The response of the reservoir to production must be matched.

Although there exists some similarities of the oil and natural gas reservoirs with geothermal reservoirs, there are some factors specific to geothermal reservoirs:

- Relatively high reservoir temperatures

- Volcanic origin of reservoir rocks with highly fractured characteristics

- Chemical precipitation of solids within the reservoir during production

- Boiling of water within the reservoir and/or wellbore

After this short introduction, fundamentals of geothermal reservoir engineering will be discussed in the following sections.

2. Types of Geothermal SystemsIn the broadest sense, the geothermal energy can be defined as the natural heat content of the earth. There are four main conditions for the existence of a geothermal reservoir with the exception of Hot Dry Rock (HDR) type geothermal sources.

1. A heat source: This heat source can be a magmatic body (> 600 °C) as well as the normal geothermal gradient of the earth as in the case of low-temperature geothermal sources. The temperature of the earth increases with a normal geothermal gradient of 3 °C/100 m. It is therefore possible to reach a depth to obtain a temperature of 70-100 °C with the existing drilling technology.

2. A heat carrier: This carrier is generally the rainwater seeping the deeper section of the earth.

3. A porous and permeable (fractured) reservoir rock.

4. An impermeable caprock.

Figure 1 represents a simple but effective diagram of a geothermal reservoir.

Geothermal systems can be classified under four main types: Vapor Dominated (dry vapor), Liquid Dominated (hot water), Geo-pressured and Hot Dry Rock.

Vapor dominated reservoirs: Although the number of these systems is limited, those systems are the most favorable geothermal systems because of the minimum risk that they carry for environment. Larderello field in Italy and Geysers field in the USA are the best-known vapor dominated geothermal reservoirs. Although hot water and water vapor can co-exist in this reservoir, vapor phase is the continuous phase determining the pressure regime of the reservoir.

Although vapor systems can have lower heat than hot water reservoirs, they are preferable because of the less problems associated with the fluid production from these reservoirs compared to hot water systems. Production mechanism of vapor-dominated reservoirs is similar to the natural gas reservoirs, expansion of reservoir fluid as production declines. The amount of fluid produced at the abandonment is generally high (85-90 % by weight of original fluid in place). On the other hand, the energy recovery has an opposite behavior. Most of the heat content of the reservoir resides in rock and extraction of heat from the rock in these systems is relatively low. Re-injection of produced fluid can increase the heat recovery from the reservoir by extracting more heat from the rock.

Liquid dominated reservoirs: Liquid phase is the continuous, pressure-determining phase in these reservoirs. The water within these systems is actually a chemical solution containing

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sodium, potassium, lithium, calcium, chloride, bicarbonate, sulfate, borate and silica. Wairakei in New Zealand, Cerro Prieto in Mexico, and Kızıldere in Turkey can be mentioned as the examples of liquid dominated reservoirs.

As it was mentioned previously, the heat recovery from liquid dominated reservoirs is higher compared to heat recovery from vapor-dominated reservoirs. The main reason of the higher heat recovery is the boiling of reservoir fluid in the reservoir and/or re-injection of the produced fluid. Production problems encountered in liquid dominated reservoirs are worse compared to that of vapor dominated reservoirs.

Geo-pressured reservoirs: Those systems contain fluids having pressures higher than hydrostatic. They generally occur in the zones covered with an impermeable layer. The pressure gradient of the trapped fluid in the formation can increase with further sedimentation and can reach up to 1 psi/ft (normal hydrostatic gradient is between 0.433-0.45 psi/ft). The temperature of these systems increase with low heat conductivity and high heat specific heats.

Hot dry rock (HDR): These systems do not contain any fluid to transfer the heat to the surface. The only way of utilizing these systems is to extract the heat energy of the rock by water circulation along an artificial fracture between two wells.

Placing the initial temperature-pressure conditions of the system on the fluid phase diagram is another classification of geothermal systems. Figure 2 shows the pressure-temperature diagram of pure water. The bold-solid line on Figure 2 is the vapor pressure curve for pure water. Geothermal fluids contain salts and dissolved gases and their phase diagram differs from pure water phase diagram. Phase diagrams of geothermal fluids containing salt and dissolved gases must be reconstructed.

The use of pressure-temperature diagrams can be explained with the help of Figure 2. Point A on the graph represents a reservoir, which is all vapor at the initial stage. Boiling point curve will never be crossed due to change in pressure under isothermal conditions (no phase change). In this type of reservoirs, the decline in pressure is very limited and the heat recovery is low. It is recommended to inject water to increase the heat recovery from the reservoir. Point B on the other hand is on the boiling point curve. Under this condition, vapor and hot water are on equilibrium. Decline in pressure due to fluid withdrawal from the reservoir will result with the shift of reservoir temperature on boiling point curve. A reservoir indicated by point C on Figure 2 is a hot water reservoir. Decrease in pressure due to production under isothermal conditions will result boiling in the reservoir, and then it will follow the boiling point curve.

Another diagram, which is frequently used in geothermal reservoir engineering, is the pressure-enthalpy diagram. Figure 3 shows the pressure-enthalpy diagram of pure water. In this diagram, the two-phase region is shown in addition to the all vapor and all liquid regions. The curve surrounding the two-phase region represents the conditions for saturated liquid and saturated vapor. The dashed lines on the diagram give the density of fluid and the solid lines indicate isotherms.

It is also possible to obtain several properties of geothermal fluid from steam tables.

3. Temperature measurementsFirst of all it should be emphasized that the temperature measurements within the wellbore represent mainly the temperature in the wellbore and does not necessarily to show the temperature of the rock surrounding the wellbore. It is well known that the temperature of the earth generally increases with depth but this increase can show different profiles (Figure 4).

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Constant temperature gradient: This type of gradient is the most common temperature profile measured. This temperature profiles are interpreted as being the result of heat conduction in the crust. (Vestman Islands and Akranes measurements in Figure 4).

Flow between aquifers: Flow in aquifers generally occurs within the closed wellbores and the flow is usually a downward flow from an upper aquifer to a lower one. In such a case, a fairly constant temperature characterizes the temperature along the wellbore over a long interval (Kaldarsel, Laugaland LJ-8 and Reykjavik G-4 measurements in Figure 4).

Negative temperature gradient: A negative temperature gradient means that the temperature decrease with depth in a part of the well. This has been observed in high temperature as well as in low temperature geothermal fields (Krisuvik H-6 in Figure 4). Although there is no common agreement about the interpretation of the negative temperature gradient, the most acceptable explanation seems to be the association of the negative gradient with non-vertical flow of water in the reservoir (Figure 5).

Warm-up period: The well and the surrounding rock are cooled down during drilling due to use of drilling fluid. It takes some time to recover its initial temperature. Increase in wellbore temperature can be the result of:

1. Heat conduction from the surrounding formations,

2. Inflow from one level to another level in the wellbore,

3. Convection within the wellbore,

4. Cross flow across the wellbore.

While impermeable layers cool down with conduction during drilling, the permeable layers are cooled down by drilling fluid depending on their fluid acceptance capacity. Transfer of drilling fluid into the permeable layers result with cold spots in these zones.

If the wellbore do not produce after drilling, the levels corresponding aquifers will warm-up later compared to impermeable layers. The opposite is observed in the case of production from the wellbore (Figures 6 and 7).

Temperature measurements during fluid injection or production can indicate the feed or loss zones under the test conditions. Figures 8-A and 8-B show the temperature profiles during fluid injection into the wellbore having three permeable layers. Figure 8-C indicates the temperature profile during production while Figure 8-D shows the profile within the closed well. 4. Well completion testWell completion test is carried out to determine the potential production zones and their effective permeabilities. Injection of cold water into the wellbore is the common procedure for the well completion tests in water-dominated reservoirs.

Two main parameters measured during water injection are:

1. Water loss: The location and characteristics of feed or loss zones are defined by measuring temperature and flow profiles in the wellbore.

2. Permeability: It is possible to determine the permeability of formation by analyzing the pressure-time records after a change in flow rate. It is recommended to refer to the petroleum engineering literature for this subject (Matthews and Russell, 1967; Earlhougher, 1977; Lee, 1982).

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Water loss test: Temperature profiles of a successful water loss test are used to indicate the permeable sections along the wellbore. Three different temperature profiles can be encountered in a water loss test (Figure 9).

Profile A: There exist a slight increase in the temperature with depth. The reason for this increase in temperature is the heating of water by heat conduction from surrounding hot formations. An abrupt increase in temperature at the deeper sections of the wellbore is the indication of stagnant water below this level. This behavior shows us the depth of the deepest loss zone.

Profile B: This type of profile is possible with the loss of water in a shallow level. The amount of water to be heated by heat conduction will be less after the loss of water at this shallow depth. This will result with a higher temperature gradient in the deeper sections of the wellbore.

Profile C: This profile is the result of hot water entry into the wellbore from a shallow reservoir.

Figure 10 gives the data of four water injection tests carried out at different times in Well KA17 of Kawerau field of New Zealand. This wellbore has more than one feed and loss zones and the first three tests were carried out when the depth of the well was 1000 m. The last test was run after deepening the well to 1400 m and the permeable zone at 650 m was cemented off.

It is better to analyze the pressure profiles that can be observed in a water loss test (Figure 11) before we start to interpret the water loss tests of well KA17. There are two high-permeability zones (A and B) in Figure 11. Pressure gradient of water-dominated reservoirs correspond to the hydrostatic pressure gradient of water at the given temperature. Pressure within the wellbore on the other hand change with the hydrostatic pressure gradient depending on the conditions in the wellbore.

During cold-water injection, wellbore pressure is lower than the reservoir pressure in the shallow sections (Level A) due to higher-pressure gradient of cold water. This pressure difference results with water entry from reservoir into the wellbore. In level B, on the other hand, the wellbore pressure is higher than reservoir pressure resulting with a loss zone. Increase in injection rate results with increase in pumping pressure although the pressure gradient remains the same. The increase in pumping pressure can carry the intersection points of two pressure curves between levels A and B to shallower depths (close to level A). It is possible to carry the intersection point at a depth shallower than level A and convert the zone at this level to a loss zone.

In case of the hot water in the wellbore, the wellbore pressure at level A can be higher than reservoir pressure resulting with a loss zone.

If we analyze the profiles given in Figure 10 under these information:

Comparison of T-2 and T-13: The two tests were run at the same rate (23 liter/s). The difference between these runs lies in the reservoir pressure. In 1967 there was no local drawdown. The 1973 run was carried out after a long period of discharge. The zone at 650 m depth was a gain zone in 1967 and became a loss zone after getting a local drawdown during 6 years production.

Comparison of T-13 and T-17: This is a standard water loss test change – a change in injection rate. In this case we see that at the higher injection rate (run T-13) the temperature step at the upper permeable zone has disappeared and there is only a change in gradient. This

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indicates that at the higher injection rate the pressures are high enough at 650 m to stop the upper inflow.

Comparison of T-17 and T-18: These two tests illustrate tests carried out before and after the well was deepened. We see that the deepening has resulted in the tapping of a deeper permeable zone. The pressure readjustment has meant that this lower zone is now the main outflow, and the 950 m zone has become an inflow in this test.

ReferencesDickson, M.H., Fanelli, M., (1995) Geothermal Energy, John Wiley & Sons, New York.

Earlhougher, R.C., Jr., (1977) Advances in Well Test Analysis, SPE Monograph Series, Volume 5, New York.

Lee, J., (1982) Well Testing, SPE Textbook Series, New York.

Matthews, C.S., Russell, D.G., (1967) Pressure Buildup and Flow Tests in Wells, SPE Monograph Series, Volume 1, New York.

Ramey, H.J.,Jr., (1970) “A Reservoir Engineering Study of the Geysers Field”, Testimony for the Trial of Reich and Reich vs Commissioner of the Internal Revenue, Tax Court of the U.S., 52 T.C. No. 74.

Ramey, H.J.,Jr., (1977) “ Petroleum Engineering Well Test Analysis-State of the Art”, Proceeding: Invitational Well Testing Symposium, Oct. 19-21, Lawrence Berkeley Lab., Berkeley, CA, pp. 5-9.

Whiting, R.L., Ramey, H.H.,Jr., (1969) “Application of Material and Energy Balances to Geothermal Steam Production”, J.Pet.Tech. (July) pp. 893-900.

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Figure 1. Schematic representation of an ideal geothermal reservoir (Dickson and Fanelli, 1995).

Figure 2. Vapor pressure curve for pure water (Whiting and Ramey, 1969).

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Figure 3. Pressure-enthalpy diagram of pure water and vapor.

Figure 4. Temperature profiles in deep drillholes in Iceland.

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Figure 5. Negative temperature gradient with horizontal flow.

Figure 6. Temperature log during warm-up period from a well in Iceland, water is flowing from the well.

Figure 7. Temperature log during warm-up period from a well in Iceland, there is no flow from the well.

Figure 8. Schematic representation of temperature profiles of a well with three aquifers at the depths of a, b and c. Curve 1 shows the true rock temperature and

curve 2 indicates the wellbore temperature shortly after drilling.

Figure 9. Some typical temperature and pressure profiles measured during cold water injection.

Figure 10. Water loss tests in Well KA17, Kawerau – New Zealand.

Figure 11. Pressure profiles during cold water injection into the wellbore.