Analytical well-test solutions are mainly derived for simplified and idealized reservoir models and therefore cannot always honour the true complexity of real reservoir heterogeneities. Pressure transients in the reservoir average out heterogeneities, and therefore some interpretations may not be relevant and could be misleading. Geological well testing refers to the numerical simulation of transient tests by setting up detailed geological models, within which different scales of heterogeneity are present. The concept of geological well testing described in this paper assists in selecting from multiple equi-probable static models. This approach is used to understand which heterogeneities can influence the pressure transients. In this paper, a low-energy multi-facies fluvial reservoir is studied, for which data from a well test of exceptionally long duration are available. The pervasive low reservoir quality facies and restricted macro cross-flow between the reservoir layers give rise to an effective commingled system of flow into the wellbore (i.e. zero or very low vertical cross-flow between the reservoir units). In our model, facies transitions produce lateral cross-flow transients that result in a ‘double-ramp-effect’ signature in the test response. A sophisticated multi-point statistical (MPS) facies modelling approach is utilized to simulate complex geological heterogeneities and to represent facies spatial connectivity within a set of generated static models. The geological well-test model responses to a real well-testing cycle are then evaluated using dynamic simulation. The pressure match between simulated and recorded data is improved by generating multiple facies and petrophysical realizations, and by applying an engineering-based hybridization algorithm to combine different models that match particular portions of the real well-test response. In this example, the reservoir dynamics are controlled by subtle interaction between high-permeability channels and low-permeability floodplain deposits. Effective integration of geology and dynamic data using modern methods can lead to better reservoir characterization and modelling of such complex reservoir systems.

High Permeability layers are a common feature of most carbonate series, and contribute to heterogeneous sweeps and early breakthroughs when injecting gas or water in an oil reservoir. The innovative workflow proposed to model the high permeability layers, on the basis of strong constraints from geological data and concepts, enables to be more predictive on the dynamic behaviour of the reservoir. It also enables a better selection of the most adapted recovery mechanism and a better strategy for optimizing the positioning of future perforations. Increasing efforts are made to track and represent high permeability layers, also named streaks, in 3D dynamic models. Well data (core description, porosity-permeability plug measurements and well tests) allow the recognition of such heterogeneity at the well. Attributing the high permeability layers to fractures or to matrix heterogeneity can be achieved by cross-checking the well data with production tests and sometimes with 3D seismic. The 3D representation of these layers, however, does not necessarily incorporate all the geological understanding that has been gathered. In the case of the studied field, offshore Abu Dhabi, the heterogeneity that is related to high permeability layers is linked to dissolution diagenesis. Dissolution diagenesis occurs preferentially just below the sequence boundaries in carbonate series. Although there are uncertainties on the dissolution trends, a stochastic modeling approach based on geological observations and concepts can help capture the effects of diagenesis on the rock properties. Multiple realizations present various equi-probable images of the field heterogeneity and will guide the field development strategy. In the first stage of the workflow, depositional environments and lithofacies have been modeled in 3D. They are constrained by the well data and the geological concept related to slope profile and to paleobathymetric control over depositional environments. Diagenesis overprints the rock texture by cementing or dissolving. Vugs are typically the product of dissolution diagenesis. No abundant dolomitization is observed in the studied formation. Dissolution diagenesis is one of the major causes of permeability enhancements in carbonates. Dissolution diagenesis preferentially occurs in the shallowest depositional environments, just below sequence boundaries when relative sea level is lowest. It is related to the infiltration of meteoric water in the carbonate series. There are three possible controls over the pathway which meteoric water can follow: the slope, the "weakest" lithofacies and early fissures or fractures in the rocks. The approach proposed to represent the effects of diagenesis is explicit. It is not currently driven by any fracture orientation. Pathways where alteration occurs are stochastically modeled on the basis of well observations and hypotheses on their orientation. Inside these modeled pathways, specific permeability ranges are entered to represent the rock properties. An interesting aspect of using an explicit approach is the quest for predictiveness of the reservoir behaviour. Most approaches related to high permeability streaks modeling today are implicit: high permeabilities observed at the wells are extrapolated away from the well by kriging or stochastic simulation methods without much geological constraints. In some cases a very fine vertical layering is chosen in order to capture even the slightest permeability variations vertically along the well.

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TX 75083-3836, U.S.A., fax ϩ1-972-952-9435 Seven scenarios were designed to account for geological uncertainties, and multiple stochastic realizations were generated for each scenario. Connected oil volume inferred from well testing was used as the main controlling parameter for evaluating the resulting facies models. Scenarios considering high channel stacking and large channels came best at honouring dynamic data. Other scenarios with models presenting a connected volume too low in the fairway, if considered or proven realistic, puts into question the role of levees in the dynamic behaviour of the reservoir.

The objective of the work was to improve the knowledge and understanding of sedimentary facies which consist of thin beds, the impact of the cut-offs, and to improve the coherency and quality of 3D models. Applying a cut-off consists in defining a threshold value on one or more logs to separate the reservoir intervals in which hydrocarbons are mobile from the gross rock thickness. In a thin beds context, this deterministic approach is insufficient because of the resolution of the logs and a limited number of data. The probabilistic approach considers that the relationship between the cut-off value on the selected log and hydrocarbon mobility in the sandy laminae is a statistical function. The method is adapted to alternating sand-shale thin beds that have not undergone extensive burial, and has been applied to reservoirs in a turbidite depositional context. In such environment, the cut-off on the VClay log is the most discriminating. The process of upscaling petrophysical properties is performed for each facies using two cellular mini-models. One is built at log resolution; the second at the scale of the cells in the reservoir model. The cut-off is applied in the log-scale mini-model using a probability function on VClay. The upscaling process provides distributions and correlation transforms for PHIE, NTG and PHIEnet which can be then used to populate the reservoir model. Transforms and Mean values differ from those obtained using a deterministic cut-off as the latter tends to underestimate the reservoir volume in shale-dominated thin bed facies and overestimate reservoir volume in sand-dominated thin bed facies.