Most gas reserves in Algeria are located in unconventional tight reservoirs that typically contain multiple rock types from different depositional systems. Identifying and evaluating these reservoirs is difficult. Permeability predictions are very challenging because of results reliability from different downhole tools, and also by its direct relationship on production and economic impact. This paper presents a case study that used an integrated formation evaluation approach of tight reservoir during an appraisal stage in an Algerian gas field. The workflow includes: – Petrophysical model using stochastic analysis to get shale volume, effective porosity and water saturation calculation. – Hydraulic flow unit zonation using flow zone indicator (FZI) and global hydraulic element (GHE) methods identified from core data. – Pressure transient analysis from wireline formation tester. – Mathematical phi-k relationship from core data under confining pressure. – Synthetic permeability log using previous relationships In addition to determining reservoir geomechanical properties from the micro frac operation, Synthetic permeability curve were generated in areas of the reservoir that were not core sampled. These predictions were constraint by core data analysis as well as permeability from wireline formation tester. This methodology was applied in an Ordovician tight sandstone reservoir in the South east Algerian Sahara gas field.

Heterogeneous carbonates formations have unique challenge to obtain representative permeability values. During the exploration phase and due to the limited number of wells and technologies, the initial formation evaluation might be misleading. The permeability results from conventional core analysis (CCA) might be significantly under evaluated because vertical interference tests from a wireline formation tester and production tests show different results. This paper describes a case study in offshore Abu Dhabi and solutions that should be assessed to overcome this challenge. An integrated approach was performed to determine the possible causes of permeability mismatch between cores, logs, wireline formation testers and production tests in this field. Based on logs and core data, the reservoir was subdivided into different layers and further refined using permeability indices from NMR logs. Formation testers with advance measurements were used to evaluate effective vertical and horizontal permeability of a single layer. The production testing covering several layers was used to fine-tune subzone permeability and subsequent flow units. The results from this study show that permeability given by CCA was somewhat misleading due to physical limitations from core plugging. The detailed core description and well-test data indicate that a significant portion of flow passes through high-permeability (vuggy) sections of the formation that cannot be measured by plugs. A formation tester was applied to check vertical and horizontal permeability in one productive zone. Various methods were integrated in the study to reconcile the unexpected high productivity of the sub-layer and explain permeability distribution from different tools. This case study provides a useful example in identifying and explaining data from reservoirs where the dynamic well productivity data differs from static data prediction.

Reservoirs in Algeria typically contain multiple rock types from different facies depositional systems, and their identification and their evaluation in some areas, is becoming more challenging. It's not easy to get a unique permeability value for specific flow-unit without combining different formation evaluation disciplines. Logs, cores and Well tests data, provide information not only of different kinds of permeability but also at different scale measurements.The presented methodology is a case study of an integrated work performed during an exploration and appraisal stage in a gas field in Algeria.The integration technique steps consisted of: • Identifying facies and hydraulic units from core data analysis • Computing permeability curve in the entire reservoir including the non-cored zones by combining logs and porosity/permeability relationship of each hydraulic flow unit. • Analyzing well testing transient pressures and estimating flow capacity.• Computing permeability at the identified flow-unit scale by the analysis of wireline formation tester data using its inflatable straddle packer configuration.The synthetic permeability curve showed a good correlation between core data and predicted values. A thickness that is actively contributing to the flow has been identified. Permeability values at the flow-unit scale were then computed.The obtained results from the integrated technique provide accurate dynamic characteristics in a gas-bearing formation and constrain the producibility knowledge of a reservoir.

The objective of this paper is focused on presenting and highlighting the results of the first successful reservoir fluid characterization and sampling attempt in offshore Abu Dhabi and the added values to the assets operating in the highly heterogeneous Jurassic carbonate reservoirs with unknown formation water salinity values. The original formation water has a unique high salinity that got mixed overtime with the fresher injection water, so that the open hole log interpretation using Archie water saturation model becomes highly uncertain. Exaggerated oil saturations could be computed within the water zones around the oil-water contact. In addition to measuring the fluid mobility, the formation testers are being run to confirm the fluid type present in the reservoir by using pressure gradient plot or by fluid identification and sampling stations. The increasing cost and rig time optimization demands inspired the team to utilize the emerging formation sampling and testing while drilling at the first time in offshore Abu Dhabi to replace the conventional wireline/ drill pipe conveyed formation testers. This application proved to be an added value to gather the required reservoir data in a mature challenging field reducing the operational time, cost and associated risks. A water injection well is drilled across a highly heterogeneous, Jurassic carbonate reservoir offshore Abu Dhabi. A deviated pilot hole was drilled for formation evaluation and reservoir fluid assessment, and the plan was to continue with a horizontal drain into one of the sub-reservoirs (swept area) if confirmed water bearing. The logging while drilling formation sampling and pressure testing tool was run combined with the conventional open hole logs to minimize the formation exposure time, real time down-hole fluid analysis started very shortly after drilling to the bottom of the target reservoir, based on the rush open hole log interpretation. Different sensors, with different physics (namely; fluid viscosity, density, sound speed, optical refractive index, temperature, fluid mobility and compressibility) were used to characterize the fluid during the pump-out stations. Due to the minimized mud filtrate invasion effects, this operational sequence allowed the gathering of conclusive formation fluid samples with less pumping time and volume. This paper shows the operational planning, design and execution outlines, discusses the benefits of acquiring clean formation samples right after drilling compared to those acquired with the conventional conveyance techniques, and indicates the drawbacks and the limitations of this technology together with any window of improvement.

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