There is considerable disagreement in the literature concerning the interpretation of wellbore damage (the skin effect) in partially completed wells. The skin factor is composed of two components, one of which is indicative of actual formation damage and the other of which results from an additional pressure drop due to the partial completion. The skin factor measured in a buildup test does not reflect the simple sum of these two components. Rather, the effect of the actual damage is accentuated by the partial completion. A method is presented to aid in the interpretation of well tests which yields estimates for both contributions to the skin factor. Analysis techniques are derived for steady-state flow and these are corroborated for transient flow by using simulated well test results. The simulations also provide a basis for comparing the various correlations for determining the skin factor due to partial penetration. The importance of the ratio of vertical to horizontal permeability is considered in the analysis. An example illustrates the application of the method. Introduction An altered zone of reduced permeability surrounding a wellbore is quantified in terms of the skin factor, s. This factor is related to the excess steady-state pressure drop1,2 in a flowing well as:Equation 1 The flow efficiency, E, is expressed in terms of Î"ps and the total drawdownÎ"pw, as:Equation 2 The skin factor has been related3 to an altered zone near the wellbore (Figure 1). If a zone of reduced permeability, ka, extends a distance, ra, into the formation, then the skin factor, s, is:Equation 3 where rw is the wellbore radius and k is the bulk formation permeability. It is the skin factor described by Equation 3 that is a measaure of the true formation damage caused by drilling and completion practices and other factors. This type of flow impediment is the target of acid treatment and other workover procedures. Thus, in order to evaluate completion practices and to recommend workover procedures, it is necessary to accurately determine the 'true' skin factor due to formation damage. In subsequent discussion this skin due to true damage will be designated as sd. The value of sd can be somewhat difficult to measure directly. A well is often completed over only a portion of the producing formation (Figure 2). This leads to a flow construction which is detected as an additional pressure drop or skin effect. Several authors4,5,6,7,8 have developed analytical descriptions of the skin factor, sp, due to partial penetration in an otherwise undamaged reservoir. In particular, Nisle9 has developed a formulation for simulating well tests within an infinite acting reservoir with a partial completion. The concept of a skin factor is not introduced.

Stylolites can be an important geologic feature affecting reservoir quality and, consequently, reservoir management, in many carbonate reservoirs. Thin, discontinuous cemented zones associated with stylolites occur in the massive, high porosity dolomites of the Upper Smackover at Jay/LEC Field and are the source of horizontal baffles to vertical flow suspected since early days of production and corroborated by full-field reservoir performance studies. It was the need for thin, vertical flow baffles to match historical waterflood arrivals in both full-field and small-area simulation modeling that led to the extensive re-examination of the core and recognition of these previously undetected cemented zones associated with stylolites. Field-wide conventional coring provides a superb core database for describing the physical nature and distribution of stylolites and associated cements. The Smackover interval is cored in over 90% of the wells (149 of the 163 wells). Porosity, permeability and fluid saturations were measured on one-inch core plugs sampled at one-foot intervals. However, small scale heterogeneities such as the reduced permeability associated with the cemented zones above and/or below stylolites were usually not captured using this unbiased core sampling procedure. The cemented zones vary from a few millimeters to several centimeters thick. Probe permeameter analysis has been used to document the decreased permeability adjacent to the stylolites. Three-dimensional geostatistical models of porosity, horizontal matrix permeability and the distribution of stylolites and cemented zones were constructed and used to derive the reservoir properties required for mechanistic simulation models. Reservoir simulations were run on models with and without the cemented zones to (1) determine what impact the cemented zones have on field performance and (2) examine alternative operating strategies for the current miscible nitrogen flood that was initiated in 1981. In the simulations, the cemented zones were assumed to have no effect on porosities and horizontal permeabilities. However, new scaled-up values of vertical permeability were generated to reflect the distribution of cements in the geologic stylolite/cement model. Results show that within the Smackover at Jay/LEC Field, the stylolite-induced baffles enhance oil recovery by reducing gravity segregation and improving the sweep efficiency of the injected nitrogen. Introduction The Upper Jurassic (Oxfordian) Smackover Formation is one of the most prolific hydrocarbon-producing formations in the Gulf Coast region. The producing trend extends in an arcuate pattern around the northern rim of the Gulf of Mexico basin from Texas to Florida. Jay Field, the largest of the Smackover fields, is located in Escambia and Santa Rosa counties, Florida near the eastern border of the Florida Panhandle (Fig. 1). It extends northward into Escambia County, Alabama where it is referred to as Little Escambia Creek (LEC) Field. Jay/LEC Field is approximately 7 miles long and 3 miles wide (Fig. 2). The Smackover Formation is at depths of 15,000 feet (4500 meters) to 16,000 feet (4800 meters) and has an average thickness of about 350 feet (105 meters). Oil is trapped in a northeast-trending anticline on the downthrown side of the Foshee fault. The fault forms the eastern barrier to oil migration and an updip trap to the north is formed by a facies change from porous dolomites to tight limestones and evaporites. Jay/LEC Field was discovered in June 1970 by the Humble St. Regis Paper Co. #1 wildcat drilled six miles south of known production. Jay/LEC Field was unitized and a waterflood using a 3:1 line drive pattern was initiated in 1974 to arrest the rapid pressure decline observed during primary depletion. The current miscible nitrogen flood, based on the water-alternating-gas (WAG) process, was initiated in 1981 to increase reserves and extend the field life. Cumulative oil production from Jay/LEC Field is in excess of 415 million barrels. P. 213^

Introduction This extended abstract describes the use of infill drilling to improve solvent sweep efficiency and EOR recovery in a gravity dominated WAG flood. Much of the incremental oil recovery in the Prudhoe Bay Miscible Gas Project (PBMGP) is displaced from a relatively small volume of swept reservoir surrounding each WAG injector. Solvent override occurs due to high vertical permeability and the large density difference between solvent and reservoir fluids. Solvent rises to the top of the reservoir or underneath shales, forming cone-shaped swept intervals around WAG injectors (Figure 1). Vertical sweep by solvent in gravity dominated WAG floods can be improved by increasing the viscous-to-gravity ratio1,2. A higher viscous-to-gravity ratio (HVGR) expands the solvent swept areas around the injection wells before gravity segregation occurs. However, little can be done in the PBMGP to reduce gravity forces, and water and solvent injection rates are currently near the maximum attainable. Reduced well spacing remains the only viable method to increase viscous-to-gravity ratio. Most of the benefit from reduced well spacing is due to displacing oil from new WAG cones around the new injectors.

Prudhoe Bay, located on Alaska's North Slope, is the largest field discovered in North America. Over eight billion barrels of oil have been produced since the start of production in 1977. Four major waterflood/miscible water-alternating-gas (WAG) flood projects are in progress in the Prudhoe Bay field. This paper describes the construction of a model representing one of these projects using a combination of stochastic and deterministic tools, and input data from the major field owners (ARCO, BP and Exxon) by personnel from multiple companies. These techniques produced porosities and permeabilities that required only minor modifications to obtain an excellent history match for the Northwest Fault Block (NWFB) area of the Prudhoe Bay field. The historical production period matched in this study included primary, secondary waterflood and tertiary miscible WAG flood mechanisms. During the history matching process, proper representation of the well's perforation and wellwork history and the existence and extent of flow barriers (e.g. shales) were important to achieving a good match. Fluxes between the NWFB and the remainder of the field were a dominant force in some predictive cases, emphasizing the importance of field-wide reservoir management. The model demonstrated a close link between overall production and management of voidage replacement requiring a good balance between productivity gains associated with reservoir fracture treatments and injection rates. Introduction The Prudhoe Bay field, outlined in Figure 1, was discovered in 1968 and was produced by primary depletion starting in 1977. Waterflooding was initiated in 1984 and most peripheral areas of the field are currently developed as pattern waterfloods. A pilot hydrocarbon WAG (water-alternating-gas) flood, the Flow Station 3 Injection Project, was started in a portion of the field in 1983, before implementation of large-scale waterflooding. The Prudhoe Bay Miscible Gas Project commenced in 1987, initially encompassing 54 patterns. Additional conversions have occurred with time, with about 70 patterns currently being WAG flooded and an ultimate total of over 130 patterns planned. The Northwest Fault Block (NWFB), delineated in Figure 2, covers the northwestern-most part of the field. It is roughly triangular in shape and is bounded to the north by a major fault. P. 359^