The goal of reservoir characterization is to generate models that allow the accurate prediction of future well performance and the estimation of reserves. Of particular importance to the characterization of permeability heterogeneity is an accurate understanding of vertical flow behaviour in a reservoir. Upscaling techniques applied to conventional core plug and probe permeameter permeability anisotropy are compared with Interval Pressure Transient Tests (IPTT) conducted with multiprobe formation testers. The aim is to investigate the scale of the dynamic permeability measurement and review the representivity of the IPTT estimate in a field example. We illustrate improvement in permeability anisotropy estimation by a combination of dynamic measurements with static measurements. Further to this, we consider the permeability prediction from continuous downhole measurement. High-resolution measurements such as probe permeametry data and borehole imaging can produce the most complete data coverage at the well and have similar measurement scales. Predicted permeabilities are compared with IPTT results by upscaling to a length scale appropriate to the IPTT and the geometry of the formation.

We present and compare three different grid-based inversion methods for estimation of formation parameters and spatial geological feature identification based on pressure transient test (PTT) data from multiple-well locations. The first and second methods employ efficient adjoint schemes to determine the gradient of the objective functions resulting in the most likely set of reservoir parameters and an ensemble of updated realizations of the parameters, respectively. The second method is based on the Langevin equation. The third method uses ensemble Kalman filtering (EnKF) for data assimilation, in which the outcome is an ensemble of updated parameter realizations. These three methods use a grid-independent prior model (in view of the limited prior knowledge of the system expected to be available), described by as few parameters as possible, and consider a non-uniform grid with the highest resolution near the wells. With these methods, the existence of and location of many sub- seismic features such as strong spatial permeability variations, faults, fractures and pinch outs may be determined using exploration and production data. Such features may not be known a priori, particularly in the exploration of heterogeneous carbonate reservoirs. We examine each method considering the degree of prior information required, the computational overhead and the applicability to the reservoir characterization workflow. Our results indicate that the first method provides a good history match to the observed PTT data and is suited for the early exploration phase of the reservoir. However, the parameters must be convolved with the smaller scale data to produce multiple realizations away from the implausibly smooth most-likely solution. The observed PTT data lies within the ensemble of predicted pressures in the EnKF and Langevin-based methods which are both applicable to probabilistic workflows where uncertainty is treated rigorously. However, EnKF seems to be computationally more efficient than the Langevin approach.

We have observed that pressure transient data gathered in most naturally fractured reservoirs tend not to exhibit the wellknown characteristic behavior, including pressure derivative, of the Warren and Root (1963) dual-porosity reservoir model. In reality, there are a rich variety of flow regimes dependent on the fracture distribution, spatial intensity and fracture conductivity. A semi-analytical solution for pressure transient behavior of fractured reservoirs has recently been presented that can be used to model the pressure response of formations with an arbitrary fracture distribution, density, and conductivity. The fractured system can be distributed discretely or continuously (network) with conductivities ranging from very low to infinite. Using the semi-analytical solution for fractured reservoirs, we perform a sensitivity analysis to identify which reservoir and geological parameters can be estimated from pressure transient test data collected from single or multiple well locations.We employ principal component analysis to explore the model parameterization as a pre-screening step. The global sensitivity analysis (GSA) methodology is then employed to determine how the uncertainty of each parameter influences the uncertainty in the output from the reservoir model. This methodology avoids the need to apply a linearized model. Our results indicate that near-wellbore region fracture conductivities have the largest contribution to the total variance of the ensemble of output pressure responses whether the well intersects fractures or not. While this is an intuitive result, GSA indicates that this parameter may be estimated independently from other geomodeling parameters unlike interpretations based on the dualporosity pressure transient solutions. This study describes how GSA is used to design a pressure transient well test for uncertain reservoir parameters.

In this paper, we present the interpretation of pressure transient well test data from discretely fractured reservoirs, where the fractures provide conduits for fluid flow and displacement, but where the fracture network is poorly connected. For this reason, dual porosity models such as Warren and Root's formulation are not usually applicable. We first outline the gaps in the existing pressure transient well test interpretation methodology for these reservoirs, then we introduce two new techniques developed to address these gaps: 1) a reservoir model-based inversion technique for the identification of spatial variation in reservoir parameters from pressure transient data, and 2) a boundary-element method for determining the pressure transient behavior of the reservoir with arbitrarily distributed finite and/or infinite conductivity vertical fractures. Using these two new techniques, we defined a new integrated interpretation methodology for reservoirs with discrete natural fractures and incorporating openhole log data, seismic, and the preliminary geological reservoir model. This is an important step in reconciling static and dynamic reservoir data to update the geological reservoir model with meaningful parameters. This methodology provides a direct means of calibrating the fracture model with the well test pressure and rate measurements-one of the few dynamic and deep-reading measurements for reservoir evaluation. Finally, we illustrated the use of the methodology, and demonstrated its robustness by using an example DST from a fractured carbonate reservoir in Campos Basin, Brazil. Results indicated the presence of discrete fractures close to and intersecting the well that do not form a connected fracture network.

We investigate the rate-transient behavior of multistage fractured horizontal wells in conventional and unconventional homogeneous and naturally fractured reservoirs, the latter of which can contain any spatial distribution of finite- or infinite-conductivity fractures of arbitrary length and orientation. The number and type of fractures (hydraulic or natural) intersecting the wellbore and self-intersecting is unlimited. We show that there are many factors that dominate the ratetransient behavior of horizontal wells intersected by multiple hydraulic fractures in naturally fractured reservoirs, such as fracture conductivity, length, and distribution, as well as whether or not fractures intersect the wellbore. It is shown that the magnitude of the fracture conductivity is one of the most important parameters that affects the production performance of multistage fractured horizontal wells. It is also shown that, as the space increases between hydraulic and natural fractures intersecting a horizontal well, the fracture pseudosteady-state flow regime tends to disappear. Using the pressure and flow rate equivalency principle, we show that a production rate and/or cumulative production data set can be transformed into an equivalent pressure or pressure derivative data set. This is also very important for unconventional gas and oil reservoirs, where the boundary-dominated pseudosteady-state flow regime takes years to develop. A new technique is presented for determining stimulated reservoir volume (SRV) and production forecasting. It is shown that rate derivatives exhibit unusual behavior, from which system identification and flow regime analysis become impossible. The material balance time does not totally correct the unusual behavior of the rate derivative. However, the deconvolved pressure of the cumulative production derivatives behave like pressure derivatives.