Geothermal reservoir characterization and well testing

After drilling a geothermal well into a reservoir, one needs to characterize its properties (lithology, fractures, stress, permeability, porosity, fluid temperature, chemical composition, etc.), and assess the well properties (i.e. determining maximum production or injection flowrate). This knowledge is essential for efficient and fast decisions, for example to configure soft stimulation treatments, as well as for the design of surface facilities.

What is reservoir characterization?

Reservoir characterization is based on various samples, analyses and measurements aiming at gathering information about the reservoirs properties and the fluid flow. Among others, geothermal reservoir characterization includes:

  • A geological characterization, in order to define the reservoir rock type and composition (lithology, facies and mineralogy);
  • A fluid characterization, in order to know fluid properties (temperature, pH, CO2/gas content, detailed chemical composition, Total Dissolved Salt (TDS), Gas Liquid Ratio (GLR), bubble point, etc.);
  • A hydraulic characterization, in order to identify the reservoir type (porous/fractured reservoir), localize flow zones and quantify the reservoir hydraulic parameters;
  • A mechanical characterization, in order to define the reservoir mechanical parameters (density, P and S-wave velocities, Young modulus value, etc.);
  • A structural characterization, in order to image the reservoir structures (fractures, faults, layering, stress field orientation and gradients, etc.)

How should a geothermal reservoir be characterized?

A geological characterization is achieved by a detailed mud logging and cutting analysis. Gamma-ray logs and spectral gamma-ray help to determine the exact depth of mud logging data and to characterize lithology, clay contents and alteration minerals.

After the production test, in order to precisely characterize the geothermal fluid, a downhole sample should be collected. Before collecting a minimum of two samples in the well’s open-hole section (feasible at once), the well should have been producing at least two times its volume. The recommended chemical analysis of the downhole sample are: GLR (Gas Liquid Ratio), a complete gas analysis, including at least CO2 and H2S, a complete fluid analysis, including physico-chemical properties (T°, pH, redox potential, Total Dissolved Salt content, electrical conductivity and total alkalinity), cations, anions and traces.

A hydraulic characterization of the reservoir is realized by combining well testing data (see below) and additional logging results. For example, a Production Logging Tool (PLT), which includes a flow log, identifies the flow zones within the reservoir section. Temperature logs, realized at the thermal equilibrium and shortly after the well drilling, also allow detecting flow zones. A neutron porosity log and a resistivity log can complete the hydraulic characterization by locating high porosity zones.

A density log allows defining the vertical stress in the framework of the reservoir mechanical characterization. A full-wave sonic log enables the calculation of the rock’s mechanical parameters, like the Young modulus. Leak-off tests and Formation Integrity tests can define the fracture pressure of the formation and the Shmin value (minimum horizontal stress).

A reservoir structural characterization should be carried out by acoustic or electrical imaging, which will image the reservoir structures (fractures, faults, layering, etc.) and thus enable an accurate estimation of the distribution of fractures orientations (dip direction, dip, thickness) in a given well.

What is well testing?

Well testing essentially consists of pumping or injection tests in order to estimate the reservoir hydraulic parameters (“hydraulic characterization”) and to answer the question “which flowrate can be pumped/reinjected from/in this well on a long term basis?”

For a single geothermal well, well testing aims at defining the following parameters:

  • Well productivity (or injectivity) index. This index is the ratio between a produced (or injected) flowrate and a pressure drawdown (or over pressure, in case of an injection). It is typically expressed in l/s/bar and depends on the flowrate. The index quantifies the ability of a well to be a poor/good producer/injector. Typical relevant injectivity or productivity values for an industrial geothermal project are above 2 l/s/bar (Baujard et al., 2017), measured at the power plant operational flowrate.
  • Well skin factor. Skin is a dimensionless factor indicating the connection of the well to the geothermal reservoir. A positive skin indicates that the near well region shows a lower permeability than the reservoir (possibly due to well damage, mud invasion and/or insufficient well cleaning), whereas a negative skin indicates that the near well region shows a higher permeability than the reservoir.
  • Reservoir permeability. Permeability (in m2 or Darcy) is an intrinsic parameter of the reservoir (it doesn’t depend on fluid parameters), indicating the ability of a fluid to flow through the reservoir. On the contrary to hydraulic conductivity (in m/s), permeability does not depend on fluid properties (viscosity, density).
  • Reservoir specific storage. Specific storage (in m-1) defines the volume of water that can be released from 1 m3 of aquifer if the hydraulic head of the reservoir decreases by 1 meter. The specific storage mainly depends on the porosity, the fluid and rock compressibility, and on the overburden weight.
  • Reservoir boundaries. A reservoir can be infinite or limited, either closed (i.e. limited by no-flow boundaries) or open (i.e. limited by one or more constant-head or constant recharge boundaries).
  • Moreover, reservoir testing allows understanding flows in the reservoir by deriving the adequate flow model (single/dual permeability for example).

For a geothermal doublet, well testing aims at quantifying the pressure connection between the two wells and the physical connection between wells.

How should a geothermal well be tested?

A geothermal well can be set in production in different ways:

  • If the well is naturally artesian, opening the main wellhead valve will make the well produce. The production rate will increase as the water column gets warmer (and lighter).
  • An airlift can ensure a sustainable production flowrate if the well productivity is not too low. An airlift consists in air injection in the drill string (typically at a depth ranging between 250 and 500m), using a compressor. In case there is a risk for a hydrocarbon gas kick, it is advisable to use nitrogen (N2) instead of air to explosions.
  • A submersible pump can be installed in the well. This solution is expensive and not adapted for hot wells (above 160°C).

In any case, it is important to maintain the wellhead pressure above the fluid vaporizing pressure in order to avoid flashing in the well, which may induce mineral scaling. A wellhead pressure above the geothermal CO2 bubble point is recommended but could be difficult to achieve.

Injections in a geothermal well can easily be realized using surface pumps.

Several tests can be realized in a single geothermal well or in a doublet:

  • A single well constant rate production (or injection) test consists in producing at a constant flowrate, and then shutting-in the well. Such a test will allow identify reservoir permeability, well skin and reservoir boundaries. The duration of such a test is typically a few days and the total produced volume is typically a few thousand cubic meters of geothermal fluid.
  • A single well step-rate production (or injection) test consists in producing at different flowrate values. Such a test will help defining the well productivity index and variable-rate skin. A minimum of 3 production steps should be realized, the duration of each steps should be identical, last for a few hours and conducted, ideally, until the pressure/temperature stabilizes.
  • An interference test consists of producing or injecting in a well, while measuring pressure in another well. Such a test will help defining the pressure connection between the wells and the reservoir parameters.
  • A tracer test consists of injecting a tracing product into an injection well, while producing at the same flowrate in a second well. Such a test will define the tracer breakthrough time and rate and help characterizing the hydraulic connection between two wells.

The following measurements should be carried out during the test:

  • Downhole pressure and temperature (PT) measurements: pressure and temperature wireline probes should be placed at the casing shoe, with at least two pressure and two temperature gauges (one wireline, one memory) to check sensors integrity and validate recorded values. The sensors should be placed at depth at least one hour before production starts, and longer if the initial downhole pressure might not be stable before the test. In any case, production should not start before the initial downhole pressure is stable. The sensors should be kept at the same position during the entire production sequence, and during the entire build-up sequence.
  • Wellhead PT measurements: at least one pressure and one temperature measurement in the wellhead, and at least one pressure and one temperature measurements in the flow-line, in order to ensure sensors integrity.
  • Flowrate: the production flowrate should be constantly measured. If it is not possible to measure the flowrate under pressure, then at least the liquid flowrate should be measured between the separator and the basin, using a V-notch weir-box and a water-level gauge (ultrasonic or pressure). The vapor flowrate can then be estimated using the flowline temperature.

Why are reservoir characterization and well testing important?

Well testing and reservoir characterization aim at gathering information to:

  1. Decide adequate well stimulation and reservoir development strategies
  2. Design adequate downhole installations and surface facilities.
  3. Obtain well and reservoir initial conditions to preserve injectivity (avoid/reduce damages at the injection well and reservoir)

Therefore, an insufficient well testing and/or reservoir characterization can lead to inefficient stimulation strategies or even counterproductive decisions and well damage. Furthermore, surface facilities might be designed inadequately. This includes for example the dimensioning of capacities for pumps, surface filters, heat exchangers, or ORC units, as well as the use of inappropriate materials. A proper design of surface facilities is essential to ensure a maximum efficiency of power/heat production, long lifetime and low maintenance costs.


Clement Baujard, Albert Genter, Régis Hehn, ES-Géothermie



Horne, R. (1996) Modern Well Test Analysis: A Computer-Aided Approach, Second Edition, Petro Way, 250p., ISBN 978-0962699214

Baujard C., Genter A.,Dalmais E., Maurer V., Hehn R., Rosillette R., Vidal J., Schmittbuhl J., (2017). Hydrothermal characterization of wells GRT-1 and GRT-2 in Rittershoffen, France: Implications on the understanding of natural flow systems in the Rhine Graben Geothermics 65, 255-268.