TX 75083-3836, U.S.A., fax 01-972-952-9435.

In general, any restriction to flow that causes a distortion of the flow lines from being perfectly normal to the borehole direction would result in positive skin. As a result, the skin factor computed from well testing is a widely used indicator of the overall flow efficiency of a given well. This is theoretically valid, but often, a high positive skin indicated from a well test is assumed synonymous with a large extent of near-wellbore formation damage and is, therefore, frequently used as a criterion to perform stimulation treatment meant to enhance the well productivity. This latter practice is generally not valid since the skin factor computed from a well test is, in reality, a composite variable that is not merely a function of near-wellbore damage. This skin factor is also a function of parameters such as perforation geometry, well deviation, partial completion, and other phase and rate dependent effects. Therefore, the skin computed from a well test must first be broken down into its constituent components in order to determine the "true" near-wellbore skin. Moreover, the skin and permeability values computed from a well test are so intimately related that an error in one directly impacts the other. Typically, additional input data would also need to be integrated in any given permeability-skin model in order to reduce the computational uncertainty. Only after proper modeling, can an appropriate stimulation treatment be selected. This is particularly important for high-deliverability gas wells, for which the formation damage-related skin often makes up only a small portion of the total well test-measured skin. This paper outlines a methodology that can be used to compute the various skin components as well as representative values of the average formation permeability from a well test. Several examples from gas wells are presented to demonstrate the utility of this methodology. Introduction to the Concept of Skin Impaired productivity of perforated completions, generally attributed to formation damage, has always been a major concern for oil companies. Formation damage can be defined as any barrier within the confines of the near wellbore reservoir or wellbore completion interval that restricts the natural production of formation fluids. The productivity, or efficiency, of a completion can be defined in terms of one or both of the following:Productivity ratio: As a ratio of the completion system's flow rate to an ideal openhole flow rate. This is sometimes called "completion factor."Skin factor: As a measure of the actual pressure drop across a completion system compared with the ideal pressure drop predicted by Darcy's Law for the same steady state flow rate. The two definitions are equivalent and are related by the following expression: where J=productivity ratio; qOH=flow from an ideal open hole completion; qp=flow from the completion system; re=drainage radius, ft; rw=wellbore radius, ft; and ST=total skin. The skin factor definition of flow efficiency is preferred for quantitative analysis as it permits estimation of discrete elements that make up the total skin. The skin factor is used to account for the additional pressure drop resulting from the resistance to flow caused by near-wellbore damage. The total skin effect can be mathematically expressed as follows: where SD is the (formation) damage skin, SC+? is the skin due to partial completion and slant, And Sp is the perforation effect.

Three productivity loss mechanisms - skin damage, water invasion, and reservoir compaction - are identified in one of the concessions co-owned by BG Group in the Nile Delta of Egypt. To inform the decision if and how to intervene to reverse the loss in productivity, it was important to understand the relative level of impact of each of these mechanisms on the observed drop in productivity. Pressure Transient Analyses (PTA) of permanent downhole gauge (PDHG) build-up data, obtained during well shut-ins, allows identification of the contribution of skin and effective permeability thickness (kh) to a given well productivity loss. By monitoring build-ups over time, any loss in observed productivity can be attributed either to increased skin or reduced effective kh. Knowing that effective kh reduction can be as a result of reservoir compaction, a reduction in net reservoir thickness due to water movement, or a reduction in relative permeability due to saturation changes, a number of control wells were selected and categorised, based on their levels of water production - negligible to low water, and moderate to high water producers. The moderate to high water producers already give indication of water breakthrough and possible gas-water-contact (GWC) movements. Time lapse PTA from these control wells enabled the tracking of changes in skin and effective kh over their producing life. The results of the investigation showed that although reservoir compaction may be occurring, the effective kh reduction for the low liquid producers is minimal. Hence increasing skin is believed to be the primary cause of the observed productivity losses. For the wells with high water cut, the productivity loss is attributed to both an increase in skin and a reduction in effective kh due to reduced net reservoir thickness and two phase flow in the reservoir.

TX 75083-3836, U.S.A., fax 01-972-952-9435.

Despite the old and extensive use of water flooding as a secondary oil recovery scheme, the actual performance of a given water flood is still often difficult to predict even in the most homogeneous of reservoirs. This performance is heavily dependent on the injection pattern, fluid mobilities, as well as reservoir heterogeneity. For this reason, it is essential that the actual performance of a water flood be measured in order to be able to optimize that performance. This is best accomplished through the combined use of reservoir saturation and production logging tools. The Reservoir Saturation Tool (RST) provides cased hole reservoir saturation using the water salinity-dependent Sigma capture cross-section measurement as well as a salinity-independent measurement of oil saturation using carbon-oxygen ratio. The latter is especially useful in fresh water and mixed/unknown salinity environments, such as might be expected in a water-injection environment. Production logging, on the other hand, provides information on zonal fluid contributions, fluid typing, as well as clues to fluid movement inside and outside the well bore. The use of shut-in as well as flowing surveys adds a third (time) dimension to the picture. This paper presents a case of water flood performance monitoring from the Younis Field, operated by the Gulf of Suez Oil Company of Egypt, and illustrates the data analysis cycle involved. The role of the analyst is to piece all the measurements together and come up with a hypothesis to explain what may be happening. This hypothesis is then tested against production data, injection data, and other reservoir data. It is then refined and fine-tuned until a satisfactory explanation is found for all the observed phenomena. The resulting conclusions are highly valuable for the assessment and subsequent optimization of the injection pattern. Background of Younis Field The Younis field (Fig.1 and 2) is located south of Ras Shukeir in the Gulf of Suez offshore the northeastern part of Egypt. The field is operated by GUPCO, a joint venture between BP-AMOCO and the Egyptian General Petroleum Corporation (EGPC). The main productive horizon is the Lower Rudies sandstone. Field production reached its first peak in 1984 after drilling and completing all the wells. A total of thirteen wells were drilled including 7 producers, 3 injectors, and 3 dry wells. A second peak came in 1986 upon application of gas lift, and a third in 1997 upon application of water injection, cleaning out of the sand, and gravel packing of several wells. Initial reservoir pressure was measured to be 1932 psi at a datum depth of 4150 ft-SSTVD. By 1996, and after the reservoir pressure had declined to around 400 psi, it became apparent that there was a dire need to provide pressure support in order to arrest the reservoir pressure decline (Fig.3). Consequently, a reservoir study was conducted to evaluate water flooding in the lower Rudies sands. The study concluded that water injection will increase recoverable reserves as well as maintain the reservoir pressure. The study also recommended initiating sand control and perforation cleaning in order to enhance production and injection rates. Upon implementing the water injection program, the reservoir pressure trend was reversed, and oil production was increased. Since the field water cut started to increase as well in response to the water injection, combined production logging and reservoir saturation measurements were run in several of the high water cut wells in order to identify the water source and to investigate the possibility of water shut-off. Field Development History The Younis field (originally called GS-347) was discovered in May 1981 and was first completed across the Lower Rudies sands (Fig.1). Based on the expected production potential, a platform was erected, and the well was placed in production in January 1983. Five wells were subsequently drilled from the Younis platform during field development.