Oil or gas effective and relative permeabilities can be reduced to a great extent due to the invading liquid phase of the drill-in or completion fluid, contrary to the misconception that formation damage is less of a concern in lower permeability reservoirs (e.g., less than 5 md). Many laboratory, well logging, and formation tester data proved that mud filtrate (both from water- and oil-based muds) can deeply invade the formation enhanced by capillary forces. This will result in reduction of the oil or gas effective permeability, especially if the formation exhibits fluid emulsion blocks and phase trapping. Unfavorable interaction of the filtrate with the reservoir fluids and rock minerals can generate emulsions and precipitates. The same scenario may occur in hydraulically fractured formations. An integrated multidisciplinary approach is pursued in this study to evaluate formation damage/remediation potential of low permeability reservoirs. The techniques involve different formation evaluation methods including core analysis, well logging, and well testing along with various cleanup scenarios. Furthermore, results from petrographic analysis and laboratory experiments (Micro and Macroscopic scales) are related and correlated with the larger Mesoscopic and Megascopic scales of well logs and well testing, respectively. Results of these efforts lead to the following technical contributions; a) Delineation of the low permeability heterogeneous reservoirs, e.g. the Leduce carbonates, into their hydraulic units. b) Determination of the undamaged formation absolute and relative permeabilities along with the diameter of filtrate invasion. c) A rule of thumb is to minimize or prevent damage from taking place by selecting a drilling fluid that quickly forms an easily removable mudcake. d) Cleaning up damage due to water filtrate may be accomplished by just flowing the well and can be accelerated using solvents or surfactants. However, once the formation reaches its irreducible water saturation, remediating water saturation below the irreducible value may not significantly improve its permeability.

Oil or gas effective and relative permeabilities can be reduced to a great extent due to the invading liquid phase of the drill-in or completion fluid, contrary to the misconception that formation damage is less of a concern in lower permeability reservoirs (e.g., less than 5 md). Many laboratory, well logging, and formation tester data proved that mud filtrate (both from water- and oil-based muds) can deeply invade the formation enhanced by capillary forces. This will result in reduction of the oil or gas effective permeability, especially if the formation exhibits fluid emulsion blocks and phase trapping. Unfavorable interaction of the filtrate with the reservoir fluids and rock minerals can generate emulsions and precipitates. The same scenario may occur in hydraulically fractured formations. An integrated multidisciplinary approach is pursued in this study to evaluate formation damage/remediation potential of low permeability reservoirs. The techniques involve different formation evaluation methods including core analysis, well logging, and well testing along with various cleanup scenarios. Furthermore, results from petrographic analysis and laboratory experiments (Micro and Macroscopic scales) are related and correlated with the larger Mesoscopic and Megascopic scales of well logs and well testing, respectively. Results of these efforts lead to the following technical contributions; a) Delineation of the low permeability heterogeneous reservoirs, e.g. the Leduce carbonates, into their hydraulic units. b) Determination of the undamaged formation absolute and relative permeabilities along with the diameter of filtrate invasion. c) A rule of thumb is to minimize or prevent damage from taking place by selecting a drilling fluid that quickly forms an easily removable mudcake. d) Cleaning up damage due to water filtrate may be accomplished by just flowing the well and can be accelerated using solvents or surfactants. However, once the formation reaches its irreducible water saturation, remediating water saturation below the irreducible value may not significantly improve its permeability.

This new technique is introduced to characterize all kinds of naturally fractured (secondary porosity) reservoirs, including carbonates, basements, and clastics on the Megascopic scale of well testing delineation. The technique is based on an original view of pressure transient data (buildup). In fact, this technique bridges between the Macro, Meso, and Megascopic scales of reservoir characterizations. Conventional well testing analysis techniques, e.g. Horner method, do not often work for naturally fractured reservoirs since they are based on a homogeneous reservoir model. In addition, all available techniques to characterize naturally fractured reservoirs from pressure transient analyses are very much theoretical models based on unrealistic geometrical assumptions. They lack practical applications and produce limited information. The new technique has the merit of working on real reservoir data. It utilizes pressure buildup data through the fact that formation fluids travel across different systems in heterogeneous naturally fractured reservoirs; matrix, fractures and the damaged area. A unique graphical characterization of shut-in well pressure versus time will illustrate the effect of fluid movements from the matrix system (or the tiny fractured system) through the main fracture system and across the damage area, if any, into the well. Fluid movements through each system are represented graphically. The technique is further optimized through application of pressure derivative methods to yield a very characteristic graphical representation (triangle)of each hydraulic "flow" unit in the reservoir. The presence of the triangle sides can be used to confirm the existence of a secondary porosity system (fractures) and/or damaged area. The slopes and intersection values of the straight lines are utilized into exclusive formulas to yield the most important petrophysical and engineering parameters about the heterogeneous naturally fractured reservoir (and, in many cases, other kinds of reservoirs) including: effective fractures, matrix and skin systems volumes, partitioning coefficient, fracture intensity index, formation resistivity factor, formation tortuosity, effective drainage radius, damage radius, effective cementation exponent, fracture porosity, matrix porosity, storativity ratio, in addition to fracture permeability, matrix permeability, damaged (skin) permeability, average permeability, pressure drop across the damage area, skin factor, damage permeability, average/dimensionless diffusivity factor, flow efficiency, damage ratio/factor, economic implication of formation damage, average hydraulic "flow" unit quality index. This document and presentation will cover the theory behind the technique and present actual field application examples.

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The problem of correcting for oil-base mud filtrate invasion has been resolved using modern well logging technology of tools and interpretation techniques. However, many well logs from old wells remain uncorrected. Old interpretation assumed no oil base mud filtrate invasion. The consequences may vary between unnecessarily perforating a water-bearing zone to even worse by completely by-passing a hydrocarbon formation. Lau et al. (1989) developed a correction for oil-base mud effects on neutron and density logs, however the standard formation evaluation techniques from the Dual Induction Resistivity Log, DIL, relies on knowledge of the resistivity of the invaded zone, Rxo. Since no electrode-type tool can work in oil base mud to measure Rxo, a synthetically derived Rxo from the Electromagnetic Propagation Time (EPT) or the Thermal Neutron Decay time (TDT) logs is used. In the absence of these unconventional EPT or TDT logs, interpretation is performed assuming no oil mud invasion and the deep induction resistivity, RID, is reading the true formation resistivity, Rt. However, it has been proven that oil mud filtrate will invade the formation sometimes to a diameter greater than 120 inches. This invasion will greatly affect Rt masking the hydrocarbon potential of the reservoir to the extent that a water zone may appear as hydrocarbon-bearing. Without proper consideration to the oil-base environment surrounding the logging tools, essential petrophysical parameters such as true formation porosity and resistivity cannot be accurately measured. Techniques and concepts such as crossplotting log j versus log Rt or log Rxo, BVW, shale zonation index, fracture partitioning coefficient, etc. may not be all conducted. Evaluation of properties such as Sw, Sxo, Smo, m, n, jma, jf, FII, etc. will not be reliable. Consequently, zonation of a heterogeneous reservoir into its hydraulic units cannot be accomplished. In this study, a new practical and cost effective technique is introduced to correctly evaluate formations with deep oil-base mud filtrate invasion of old well logs in the absence of EPT, TDT, logs, i.e. without a prior knowledge of Rxo or Rw. This will allow characterization of old reservoirs drilled with oil-base muds using the available old conventional well logs without the need for running new expensive well logs.