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dwindle and exploration/development costs escalate particularly in frontier regions, the need for effective prevention and/or treatment of formation damage to maximize well productivity, has become apparent to prudent operators. This paper discusses wmomic implications, reviews various origins and forms, and provides method for recognition of formation damage. Geological and enoneering tests for Proper assessment of the problem, and optimization schemes for effrctive solution are also describe. BACKGROUND Formation damage is a condition which occurs when barriers to flow develop in the near-wellbore region to give rise to a lower than expected production rate from or injection rate into a hydrocarbon bearing reservoir rock. This problem has been recognized for several decades as a major contributor to anomalous production and/or abnormal decline in productivity or injectivity in most hydrocarbon reservoirs. Many potential pay zones have been misdiagonized as nonproductive, and payout on investment has been delayed because of formation damage. Understanding formation damage requires a multidisciplinary approach that involves such diverse specialty fields as inorganic/organic chemistry, physical chemistry, colloid and interfacial sciences, chemical kinetics, mineralogy, diagenesis and 65-1 fluid transport through porous media. Unfortunately, the primary interest of the various field groups involved in reservoir dermition and exploitation often seem to be in conflict. For instance, the driller is typically interested in reaching the targeted depth quickly( increased ROP), and safely (overbalance pressure condition), while maintaining a gauged hole. Avoidance of formation damage then appears to be of secondary concern.However, if a project team is formed at the outset to include drillers, mud engineers, geologists, production and reservoir engineers, then proper objectives of a safe drilling program can be set to protect the formation and to casure that the reservoir will be exploited to its maximum productive capacity to generate a maximum return on investment. Once formation damage has occurred, proper assessment and treatment WW require the cooperative effons of geologists and enpneers both in the field and in the laboratory. This synergistic approach is necessary to develop effcclive solutions to this expensive problem. Better understanding of the mechanism of formation damage is required in ordcr to develop effective preventive and mitigative procedures. With recent advances in technology, laboratory geological and engineering measurements can provide the many insights into the mechanism, prevention and cffcctive treatment of formation damage.

SPE Member Abstract Description of reservoir rocks in terms of complex variations in hydraulic properties, heterogeneity and geometry requires a synergistic, multidisciplinary engineering and geological approach. This paper presents a practical systematic approach to integration of various core analysis data for reservoir description. Various petrophysical parameters are strongly correlated with pore space attributes using the mean hydraulic radius,. Additionally, empirical equations are presented for transforming lab-derived core properties to appropriate reservoir in-situ stress conditions. Introduction The performance of a hydrocarbon bearing reservoir is largely controlled by certain intrinsic properties of the porous medium. According to Haldorsen, reservoir description can be defined as "Combined efforts aimed at discretizing the reservoir into subunits, such as layers and grid blocks and assigning values of all pertinent physical properties to these blocks." Understanding the complex variations in hydraulic properties (porosity, permeability, capillary pressure, and relative permeability), reservoir heterogeneity and geometry (morphology and continuity) requires a multi-disciplinary synergistic approach that involves the efforts of engineers and geoscientists. Effective description of the reservoir is key to efficient reservoir management. Typically, data from various sources are utilized to describe the reservoir in terms of pore space, attributes, distribution and geological attributes. These sources include cores, logs, seismic tomography, well test and production history data. Harris et al. emphasized the importance of synergy in reservoir management and discussed the interplay of geological and engineering factors on reservoir description. Several other authors (Sneider and King, Hietala et al.; Neasham, Swanson) have discussed the integration of core and log data for formation evaluation. However, none of these authors documented how to appropriately zone the reservoir into hydraulic units or how to average macroscopic parameters for input into numerical simulators. Keelan earlier presented a treatise on the use of core analysis data as aid in reservoir description and reviewed the various analyses (routine, complementary and special) performed on core samples. He discussed the variety of measurement protocols, characterized certain rock properties (porosity, permeability, grain density and capillary pressure) and showed how these properties varied with the geological factors such as the environment of deposition. Core sample analysis provides the fundamental building block for reservoir description. Core specimens are the only representative elements of the reservoir rock that are physically available for examination and modeling of basic flow processes. As such, data from analysis of cores must be properly understood before application in numerical simulators. Whereas core samples provide basic information on the reservoir rock at both microscopic (pore level) and macroscopic (core plug) levels, wireline logs, wireline tests and well tests provide moving averages of reservoir properties on a megascopic level. These megascopic measurements, though representative of a larger volume of scale, must be calibrated with data from the physical model (core specimen) to validate the mathematical models and assumptions on which they are based. Furthermore, it is extremely important to understand the relative volumes of investigation and associated uncertainties of the various reservoir description measurements. This paper presents a practical systematic approach to integration of various core analysis data for reservoir description. Techniques are discussed for zonation of the reservoir into hydraulic units. The roles of geological processes-diagenesis and depositional facies on primary rock properties (texture, fabric, sedimentary structures) and their resultant effects on reservoir rock quality and performance are discussed. Various petrophysical parameters are correlated with pore space attributes (geometry and distribution). Techniques are presented for relating clay morphological properties (types, distribution, location, CEC) to macroscopic rock properties, electrical properties (F, m, n); mean hydraulic radius, capillary pressure, liquid permeability and relative permeability. Empirical equations are derived to relate certain rock properties (porosity, permeability, inertial resistance coefficient/turbulence factor p, and compressional/shear wave velocities) to reservoir stress values. These relationships then permit proper transformation of laboratory derived rock properties to appropriate in-situ stress conditions.