Technique and technology combine to enable successful Frac-pack completions near water contacts.

As the quality of prospects continues to decline, Gulf of Mexico shelf wells must have improved completion efficiency to maintain project profitability. This article reviews the application and results of performing frac-pack completions on several central to western Gulf of Mexico shelf region gas and oil wells that have water contacts within the productive zones. Individual project economics were based on achieving efficient completions with minimal initial water production. The main topics to be evaluated are design considerations, treatment review, case history well data and production results.

Frac-packing replaces other techniques

Since the early 1990s, frac-packing has become the preferred completion method for new wells in the Gulf of Mexico. Documented frac-pack completion successes can be found in numerous Society of Petroleum Engineers (SPE) papers and magazine articles. Along with productivity enhancements came completion efficiency improvements which reduced total completion time and cost.

Expanding frac-pack applications

Frac-packing success has led the industry to push the range of application. Just a few years ago, the frac-pack candidate selection process faced several limitations: moderate or laminated permeability, temperatures, rates and proximity to unwanted contacts (water or gas cap). Fluid enhancements and aggressive modifications or upgrades to both surface and downhole equipment have allowed the industry to overcome most of these initial limitations. Early changes (from linear fluids to cross-linked fluids) allowed higher temperature and permeability formations to be treated with reduced volumes and rates. Improved downhole tools and pumping equipment led to treatment designs better suited to achieve superior (tip screen-out) fracturing success.

Treatment design considerations

Completion efficiency and project economics are key factors for successfully completing marginal zones with water contacts. Part of the up-front financial success realized from frac-packing comes from increased production due to the ability to bypass overbalanced perforating damage. Overbalanced perforating typically saves 1 to 3 days completion time, which can be an enormous savings over a multi-well package.

Candidate selection starts with evaluating zonal isolation during primary cementing to reduce the possibility of water production from channeling. In the cases reviewed here, downhole tool configurations changed to meet specific wellbore and future production needs, but typical frac-packing hardware was used. Frac-packing was the selected completion method due to the technique's success throughout the Gulf of Mexico. Potential concerns of fracturing into the water and increasing initial water production were addressed with modified fracturing designs.

Initial fracture modeling designs are developed using well information. Treatment volumes are calculated based on input data. Figure 1 shows how the stress profiles and fracture growth are used to determine height growth towards the water zone. Treatment fluids and rates are designed to control height growth. If cross-linked fluid causes excessive growth, then linear gel fluid can be used.

Once fluid determination is made, stress differences are removed to evaluate unrestricted height growth. In most cases, attempts to restrict growth into the water zone resulted in reduced frac-pack treating volumes. Crossed-linked fluid treatments were ramped quickly to achieve maximum proppant concentrations of 10 ppa to 12 ppa (pounds proppant added per gallon of fluid), while linear gel fluid treatments were limited to maximum 4 ppa to 8 ppa concentrations.

Reviewing the treatment process

Most of these wells were frac-packed using cross-linked fluid. When cross-linked fluid was used, both the mini-frac and frac-pack used it and the step-rate test used linear gel.

Some of the treatments used linear gel as the carrier fluid. Due to the quick fluid leak-off of the linear fluid, the mini-frac tests typically are omitted. In these cases, model calibration was performed using step-rate test data.

Calibration starts with injection and circulation tests followed by spotting the acid treatment to the tool. Once the acid is on bottom and the tool has been shifted (weight down circulating position if the wellbore conditions allow, squeeze position if they do not), the acid is injected into the formation and is flushed with the mini-frac and step-rate fluids. After a shutdown period with the acid in the formation, the mini-frac is pumped. The step-rate test follows the mini-frac pressure decline. A pH buffering agent can be added to the step rate fluid to help restore the reservoir to its initial conditions before the mini-frac. Fracture model analysis and matching of the calibration test data is necessary to generate a redesigned frac-pack treatment schedule.

During the analysis process, the flush fluid is reversed if allowed by location conditions. If the flush fluid is reversed, the frac-pack treatment would be spotted. If the flush fluid cannot be reversed, it would be bullheaded in front of the frac-pack. The aggressive proppant ramps and flush fluid restraints require special attention on the spotting procedures to ensure job success.

Treatment schedules for the 12 case wells are displayed on Tables 1 and 2.

Well data and production results

The case history data describes production from five gas wells (Table 3) and seven oil wells (Table 4). Measured depth (MD) perforated intervals ranged from 12 ft to 50 ft (3.6 m to 15.2 m) for the gas wells and 22 ft to 50 ft (6.7 m to 15.2 m) for the oil wells. Perforated intervals for each zone are listed along with MD and true vertical depths (TVD) from the water contact. The tables show frac-pack treatments were attempted as close as 4 ft (1.2 m) TVD from the water contact. This aggressive approach was taken to analyze the ability of a frac-pack to reduce near wellbore draw-down and delay water production.
The gas wells, as expected, seemed to respond better and were more definitively successful than the oil wells. Four out of the five gas wells were successful, with the only questionable case being well #4 [with the water contact only 7 ft (2.1 m) TVD away in a highly deviated well].

All of the oil wells except well #5 reported low initial water production. The initial water production for well #5 may have been influenced by completion fluid cleanup. In oil well #4 the water contact was 6 ft (1.8 m) MD and 4 ft (1.2 m) TVD away and water production increased within 3 months. Oil wells #1 and #6 have made water after experiencing excellent hydrocarbon production for at least 1 year. Although oil well #7 continues to produce at high rates, the cumulative water production is very high.

Summary and conclusions

The data show that frac-pack completions can successfully be applied even with the presence of a nearby water contact. Careful examination and job performance is required when frac-packing on top of water. Gas wells seem to respond favorably with caution advised as the true vertical distance from the water contact drops below 10 ft (3 m). For oil wells, concern may arise when the true vertical distance from the water contact falls within 20 ft (6.0 m). The difference between the gas and oil wells probably results from the different mobility ratios compared to water.

Frac-packing with a water contact present has been tackled successfully. This data shows some hurdles remain as the perforated interval gets closer to the water contact. Do not interpret this as an unachievable boundary, because it is only a challenge for the future.

Future treatment fluids may include relative permeability modifiers that would allow frac-packing into the water zone with minimal chance of initial or long-term water production.

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