This paper discusses the application of radio-active tracer and temperature surveys and resulting information to evaluate the effectiveness of fracture design and placement in Vicksburg sands in Shell's McAllen Production Unit. The data obtained has resulted in improved methods of completion design and fracture effectiveness.
Large fracture treatments with high viscosity fluids and high proppant concentrations have been performed routinely, since 1970, at three Shell-operated performed routinely, since 1970, at three Shell-operated South Texas-Vicksburg Fields -McAllen Ranch, Javelina/East McCook and La Copita (Figure 1).
The geopressured Vicksburg reservoirs occur at depths from 9,000 to 16,000 feet (2,745 to 4,875 meters) with reservoir temperature ranging from 260 deg. F to 350 deg. F (400K to 450K) and reservoir pressure gradients up to 0.93 psi/ft (21.04 KPa/M). The reservoir rock is composed of very fine grained quartz and feldspar grains in a clay matrix and about 20% calcite pore in-filling resulting in permeabilities of less than 0.5 md. Due to the permeabilities of less than 0.5 md. Due to the high acid solubility of the rock's calcite cementation and the resultant loss of formation strength following acid treatments, hydraulic fracturing has been the primary stimulation method used.
Due to the deltaic depositional environment of the Vicksburg reservoir, the sand distribution is erratic, often resulting in only a fraction of a gross thickness of 300 to 600 feet (90 to 180 meters) being reservoir quality rock, An average Vicksburg well (prior to 1977), was completed in 90 net feet (27.4 net meters) of gas pay spread over a gross interval of 350 feet (105 meters). The pay sands were selectively perforated (8 to 16 shots), as seen in Figure 2, for limited entry fracture design. Due to the long completion intervals, multistage fracturing was employed for many completions. Table 1 is a typical fracture design for this type completion.
Prior to fracturing, an average well would produce 1,200 MCFD (33,980 M3/D) at 4,000 psi produce 1,200 MCFD (33,980 M3/D) at 4,000 psi (27.6 MPa) flowing tubing pressure. Following the fracture treatment, production normally increased to 3,500 MCFD (99,110 M3/D) at 7,500 psi (51.7 MPa) flowing tubing pressure. High (5 to 10) folds of production increase are seldom attempted due to the production increase are seldom attempted due to the potential hazard of producing proppant by drawing potential hazard of producing proppant by drawing the well down too rapidly.
In 1976, the effectiveness of multistage fracturing in the McAllen Unit was questioned. At this time, a program was initiated to tag the last 3,000 to 5,000 gallons (11 to 19 M3) of proppant laden fluid with radioactive sand and to run gamma ray logs after fracturing. Very little direct information was obtained from the first few tracer surveys; however, it was discovered that large amounts of proppant fill were falling out in the casing during pumping operations (this prevented evaluation of sands by logging) with as much as 80% of the total pay being covered with proppant, as exhibited in Figure 3. In early 1977, changes were made to enhance the chance of successfully evaluating multistage fracturing. The changes and results were:
Bottom was tagged between stages of multistage frac jobs prior to dropping diverters. By tagging bottom betweenstages, it was determined that in most cases the lower interval (2nd stage design) was already covered with proppant prior to dropping ball diverters, thus eliminating any chance of a successful job.
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