Reservoir Permeability Determination Using After-Closure Period Analysis of Calibration Tests
- Said Benelkadi (Sonatrach) | Djebbar Tiab (U. of Oklahoma)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- June 2004
- Document Type
- Journal Paper
- 230 - 237
- 2004. Society of Petroleum Engineers
- 4.6 Natural Gas, 2.2.2 Perforating, 5.6.3 Pressure Transient Testing, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.1.2 Separation and Treating, 5.5.2 Core Analysis, 4.3.4 Scale, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.2 Reservoir Fluid Dynamics, 3 Production and Well Operations, 5.1.1 Exploration, Development, Structural Geology, 5.6.1 Open hole/cased hole log analysis, 5.6.4 Drillstem/Well Testing, 5.6.2 Core Analysis, 2.5.1 Fracture design and containment, 2.4.3 Sand/Solids Control
- 0 in the last 30 days
- 588 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 5.00|
|SPE Non-Member Price:||USD 35.00|
Hydraulic fracturing generally has been limited to relatively low-permeability reservoirs. In recent years, the use of hydraulic fracturing has expanded significantly to high-permeability reservoirs. The objectives of fracturing low-permeability reservoirs and high-permeability reservoirs are defined by reservoir parameters.
The estimation of reservoir permeability, a variable of great importance in hydraulic fracturing design, is frequently unknown because either candidate wells do not flow or pretreatment pressure-transient testing is required. Consequently, Nolte et al.1 introduced a new method for adding after-closure fracturing analysis to the pretreatment calibration testing sequence that defines fracture geometry and fluid-loss characteristics. The exhibition of the radial flow is ensured by conducting a specialized calibration test called the minifalloff test. Using the theory of impulse testing and the principle of superposition, Nolte et al.1 developed a method that allows the identification of radial flow and, thus, the determination of reservoir transmissibility and reservoir pressure.
This work proposes a new method for determining reservoir permeability. The method also offers the potential for determining the average reservoir pressure. This procedure is based on the use of the pressure derivative, and it requires only one log-log plot for the identification of the radial-flow regime and the determination of reservoir parameters.
The application of the proposed method is demonstrated on real field data from calibration tests performed on several oil and gas wells. The reservoir parameters (particularly permeability) determined with this method are verified by comparison with results obtained from pressure-buildup tests. Other sources, such as core analysis, lend support to the permeability estimated with the proposed technique.
Hydraulic fracturing has been recognized as an effective means for enhancing well productivity and recoverable reserves, especially for low-permeability reservoirs. The appropriate fracturing treatment for a given well has been difficult to design because of the numerous variables involved. The use of inaccurate reservoir variables to design treatments may lead to poor production estimates.
In wells that are to be hydraulically fractured, minifracture treatments, also called "calibration" tests, are frequently performed to determine the parameters needed for the stimulation design. They are generally performed without proppant.
Fracture-pressure analysis was pioneered by Nolte.2,3 The basic principles are analogous to those for pressure analysis of transient fluid flow in the reservoir. Both provide a means to interpret complex phenomena occurring underground by analyzing the pressure response resulting from fluid movement in reservoirs.
The analysis of fracturing pressure, during periods of injection and after closure, provides a powerful tool for understanding and improving the fracture process. Advances in mini-fracture-analysis techniques have provided methods for the determination of fracturing-treatment design parameters such as leakoff, fracture dimensions, fluid efficiency, closure pressure, and reservoir parameters. These parameters can then be used to determine the pad volume required, the best fluid-loss additives to be used, and how to achieve the optimum fracturing-treatment design.
Fig. 1 shows a typical history of the calibration test from the beginning of pumping until the reservoir disturbance. Fracturing pressures during each stage of fracture evolution (i.e., growth, closing, and after closure) provide complementary information pertinent to the fracture-design process. Therefore, fracturing-pressure analysis may be reduced to three distinct types of analysis.
Fracturing-Pressure Analysis for Pumping Period.
The basis for interpreting fracturing pressure is to use the net pressure (fluid pressure inside the fracture). The behavior of net pressure with time is related to the hydraulic fracture geometry, including confined or unconfined height and length and rate of growth with time. The magnitude of the net pressure is controlled by fracture geometry, the elastic modulus of the formation, and (to a lesser extent) the fluid viscosity and pump rate. The most common method used to interpret pressure during injection is the Nolte-Smith plot,5 which determines the type of model [Perkins, Kern, and Nordgren (PKN);6,7 de Klerk, Geertsma, and Daneshy (KGD);8 or radial] to use for decline analysis.
Fracturing-Pressure Analysis for Closing Period.
Fracture parameters can be determined from pressure decline using the Nolte type curve2 or the "G"-function9 plot. The confirmation of closure pressure also can be done with the square root of time plot. The closure pressure is inferred from the slope of either of these plots. These methods normally do not provide a definitive indication of the closure pressure because of the existence of multiple slope changes.
Fracturing-Pressure Analysis for the After-Closure Period.
The last fracturing analysis pertains to the evaluation of pressure following fracture closure. The pressure response during this period loses its dependency on the mechanical response of an open fracture. It is governed by the transient-pressure response within the reservoir. This response, which results from fluid loss during fracturing, can exhibit a late-time radial response. This flow pattern can be addressed in a manner analogous to conventional well-test analysis. Economides and Nolte10 suggested that a specialized test called a mini-falloff test can allow the exhibition of the radial flow during a practical shut-in time. The determination of reservoir permeability and reservoir pressure, using after-closure analysis, is similar to Horner analysis.11
|File Size||1 MB||Number of Pages||8|